[Federal Register Volume 68, Number 34 (Thursday, February 20, 2003)]
[Rules and Regulations]
[Pages 8402-8435]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 03-3425]



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Part III





Department of the Interior





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Minerals Management Service



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30 CFR Part 250



Oil and Gas and Sulphur Operations in the Outer Continental Shelf--Oil 
and Gas Drilling Operations; Final Rule

  Federal Register / Vol. 68, No. 34 / Thursday, February 20, 2003 / 
Rules and Regulations  

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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AC43


Oil and Gas and Sulphur Operations in the Outer Continental 
Shelf--Oil and Gas Drilling Operations

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Final rule.

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SUMMARY: This final rule restructures the requirements for oil and gas 
drilling operations on the Outer Continental Shelf (OCS), adds some new 
requirements, and converts the regulations into plain language. The 
restructuring of the rule follows the logical sequence of obtaining 
approval to drill a well and conducting drilling operations. The final 
rule also removes overly prescriptive requirements and updates 
requirements to reflect changes in drilling technology. Restructuring 
the drilling requirements makes the regulations easier to read, 
understand, and follow. The technical changes will help ensure that 
lessees conduct operations in a safe manner.

EFFECTIVE DATE: The rule is effective March 24, 2003. The incorporation 
by reference of publications listed in the regulation is approved by 
the Director of the Federal Register as of March 24, 2003.

FOR FURTHER INFORMATION CONTACT: William Hauser, Engineering and 
Operations Division, at (703) 787-1613.

SUPPLEMENTARY INFORMATION: On June 21, 2000, we published a Notice of 
Proposed Rulemaking (65 FR 38453), titled ``Oil and Gas and Sulphur 
Operations in the Outer Continental Shelf--Oil and Gas Drilling 
Operations'' to revise the subpart D regulations of part 250, with 
exception of the regulations on Hydrogen Sulfide under 30 CFR 250.417. 
The proposed rule had a 90-day comment period that we extended to 120 
days on July 27, 2000 (65 FR 46126). The extended comment period closed 
on October 19, 2000.

Differences Between Proposed and Final Rules Not Directly Related to 
Comments

    In addition to changes we made to the final rule in response to 
public comments, we reworded several sections to further clarify the 
requirements. We also changed several section titles to better reflect 
the intent of the sections. The following are the changes by section:
    [sbull] Section 250.403--We divided the requirements contained in 
the table in this section into three new sections. We believe this 
change provides a better understanding of the requirements. The new 
sections are:

250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines on a 
drilling rig?
250.406 What additional safety measures must I take when I conduct 
drilling operations on a platform that has producing wells or has other 
hydrocarbon flow?
    [sbull] New Sec.  250.405--We added engines on escape capsules to 
the list of diesel engines that you do not have to equip with an air 
intake device. We believe that this device should not be required on an 
escape capsule. We also revised paragraph (b) by adding the term 
``remote'' to manual air intake shutdown device so that the requirement 
means the same as the previous requirement. Paragraph (b) now reads as 
follows: ``For a diesel engine that is continuously manned, you may 
equip the engine with either an automatic or remote manual air intake 
shutdown device;''.
    [sbull] New Sec.  250.406(b)--This paragraph applies to shutting in 
producing wells during the movement of a drilling rig on and off a 
location. We clarified the requirements of this section in response to 
comments from the Offshore Operators Committee (OOC) (see discussion in 
OOC comments section). We want to further clarify in the preamble of 
this rule that the same requirements to shut in producing wells would 
apply when a lessee moves in a drilling rig or coiled tubing unit to 
complete or workover a well. We plan to clearly state these 
requirements for completion and workover activities in revisions of 
subparts E and F that we anticipate proposing.
    [sbull] Sections 250.408 and 250.409--We added two new sections to 
address the use of alternative procedures or equipment during drilling 
operations and obtaining departures from the drilling regulations. We 
made this revision to clearly state the procedures for using 
alternative procedures or equipment and for obtaining departures from 
the drilling regulations. We also removed phrases similar to ``or as 
otherwise approved by the District Supervisor'' throughout the rule 
because you may request a departure or the use of alternative 
procedures or equipment with respect to any of the drilling 
requirements prescribed in the rule, provided the rationale is 
appropriate.
    [sbull] Section 250.414--We added an introductory sentence to this 
section which states that the drilling prognosis must include a brief 
description of the procedures that you will follow in drilling the 
well. That description includes the nine items listed (a) through (i) 
in this section and any other events or procedures that are out of the 
ordinary for drilling activities. We also moved the paragraph on 
listing and describing departures or requests to use alternative 
procedures and equipment to this section.
    [sbull] Section 250.421(d)--We revised this paragraph to read as 
follows: ``As a minimum, you must cement the annular space 500 feet 
above the casing shoe and 500 feet above each zone to be isolated.'' We 
inserted the phrase ``500 feet above'' before ``each zone'' to ensure 
that there was no confusion about cementing requirements for the 
intermediate casing. This clarification is consistent with the current 
regulations.
    [sbull] Section 250.424--We converted the requirements for pressure 
testing casing into a table. This will make the requirements easier to 
understand.
    [sbull] Section 250.427--We clarified the requirement for when you 
must conduct a pressure integrity test after drilling new hole below 
the casing shoe. The original requirement stated a maximum amount that 
you could drill before conducting the test (50 feet). The revised 
requirement has both a minimum (10 feet) and a maximum (50 feet) amount 
that you could drill before conducting the test. This will remove any 
confusion about how much new formation you must drill before conducting 
the test.
    [sbull] Section 250.465(a)(3)--We revised this paragraph to require 
the submittal of a plat certified by a registered land surveyor when 
you determine the well's final surface location, water depth, and the 
rotary kelly bushing elevation. This requirement is consistent with the 
current regulations. The certified plat serves a useful purpose because 
it provides certainty to the well's location. In some instances, 
submittals of non-certified plats or reliance upon the planned location 
plat provide only a rough idea of where the well may be located.

Changes to Drilling and Well Forms Not Related to Comments

    Through a separate process, MMS revised the associated 30 CFR 250, 
subpart D, drilling and well forms MMS-123, MMS-123S, MMS-124, MMS-125, 
and MMS-133. We are conducting the form revisions in compliance with 
the requirements of the Paperwork Reduction Act of 1995 (PRA), and as 
part of our efforts to implement the Government Paperwork

[[Page 8403]]

Elimination Act and streamline data collection. The revised forms were 
published for comment in the Federal Register on May 1, 2002 (67 FR 
21718). In addition to revising some of the data elements on each form, 
we changed the titles of forms MMS-124 (Sundry Notices and Reports on 
Wells changed to Application for Permit to Modify), MMS-125 (Well 
Summary Report changed to End of Operations Report), and MMS-133 
(Weekly Activity Report changed to Well Activity Report). In accordance 
with the PRA, we submitted the revised forms to the Office of 
Management and Budget (OMB) for approval. The OMB approved the use of 
the new forms in October 2002 and these final regulations incorporate 
the changes to the forms.

Comments on the Rule

    We received 11 sets of comments on the proposed rule and other 
considerations for drilling regulations. The comments came from four 
oil and gas lessees/operators (Chevron USA Production Company, Shell 
Exploration & Production Company, Torch Operating Company, and Mariner 
Energy), two drilling contractors (Noble Drilling Services and Rowan 
Companies), three trade organizations (American Petroleum Institute 
(API), OOC, and International Association of Drilling Contractors 
(IADC), one consultant (West, Inc.), and one private citizen (James E. 
May). You may view these comments and the Notice of Proposed Rulemaking 
(NPR) on the MMS Web site at address: http://www.mms.gov/federalregister/PublicComments/rulecomm.htm. The OOC and IADC provided 
the most comprehensive sets of comments on the proposed rule. Three of 
the operators and both drilling contractors fully supported the 
comments of their respective trade organizations and provided 
additional comments. The API noted that it worked with OOC in preparing 
detailed comments on the rule and fully supports the comments submitted 
by OOC. The OOC presented its comments on specific sections of the rule 
in a table that identified the section, suggested changes, and provided 
rationale for those changes. We found this to be an informative format 
for reviewing comments and have used that format to respond to OOC's 
comments.
    We organized our responses to comments on the NPR into three 
sections. These sections address the following topics:
    I. General comments and comments on other considerations for 
drilling regulations (i.e., need for regulations on the use of coiled 
tubing, mandatory use of automated pipe handling systems);
    II. Comments on specific sections that OOC did not address in its 
comments; and
    III. OOC's comments on specific sections (table format).

I. General Comments and Responses

    [sbull] Comment: The use of Lessees/Operators/Contractors relates 
better to these regulations than the use of ``I'' and ``you.''
    Response: We disagree. The use of ``I'' and'' ``you'' in the 
regulations essentially replaces the terms ``lessees, operators, and 
contractors.'' It is much easier to say ``you must'' versus the 
``lessee/operator/contractor must.''
    [sbull] Comments on Incorporating API Recommended Practice (RP) 53, 
Recommended Practice for Blowout Prevention Equipment Systems for 
Drilling Wells (API RP 53) into the regulations: One commenter stated 
that the incorporation of specific sections of API RP 53 is appropriate 
because incorporation of the entire document would lack the specificity 
needed for the regulations. Another commenter recommended that the 
entire contents of API RP 53 should be incorporated by reference to 
provide overall guidelines for blowout preventer (BOP) systems.
    Response: MMS has incorporated specific sections of API RP 53 into 
the regulations as proposed. The primary reason for selecting specific 
sections was to provide needed specificity to the existing 
requirements. However, API RP 53 provides excellent guidelines for 
operating and maintaining BOP systems, and MMS will consider 
incorporating the entire document in a future revision of the drilling 
regulations.
    MMS will also consider the incorporation of other API drilling 
documents. MMS recently contracted with West, Inc. to review and 
compare three API Recommended Practices to MMS regulations and IADC's 
Deepwater Guidelines. The three Recommended Practices are:
    1. 16E--Design of Control Systems for Drilling Well Control 
Equipment;
    2. 64--Diverter System Equipment and Operations; and
    3. 16Q--Design, Selection, Operation, and Maintenance of Marine 
Drilling Riser Systems.
    West, Inc.'s complete report is available on the MMS Web site at 
ftp://www.mms.gov/TARProjects/380/380AA.pdf.
    [sbull] Comments on Automated Pipe Handling Systems: This topic 
generated many comments, most of which disagreed with requiring 
automated pipe handling systems. Comments against requiring these 
systems included the following:

--Little data exist to support the theory that automated pipe handling 
systems measurably improve personnel safety;
--Automated pipe handling systems create new safety hazards (i.e., new 
pipe racking systems have introduced additional tripping hazards to rig 
floor personnel which have resulted in lost time incidents);
--Costs (including capital and out-of-service time) to retrofit the 
drilling units would not be justified considering the perceived safety 
benefits;
--Some drilling units could not be retrofitted due to space limitations 
and/or due to the added weight of the automated pipe handling 
equipment; and
--Reliability is an issue with some automated systems

    Other comments questioned if automated systems meant totally 
automated pipe handling systems or just a subset of automated rig floor 
equipment such as iron roughnecks, spinners, and power slips. 
Commenters also asked if operations would have to be suspended if the 
automated systems were not available due to downtime. While the vast 
majority of the comments were against requiring automated systems, one 
comment said that MMS should require some automated rig floor 
equipment, but those requirements should be flexible and a practical 
application of existing technology.
    Response: MMS appreciates the comments industry has provided on 
this topic, and we now have a better understanding of how a requirement 
for an automated pipe handling system could impact the drilling 
industry and drilling operations. One of the purposes for raising this 
issue in the preamble of the proposed rule was to elicit this 
information. This final rule does not include any requirements for 
automated pipe handling systems or automated rig floor equipment. Nor 
is MMS proceeding with any proposed regulations on these systems at 
this time.
    [sbull] Comments on Best Cementing Practices: Most comments were 
along the lines that best cementing practices should be used where 
possible, but that specific practices should not be mandated by 
specific requirements. OOC stated that the complexity of cementing 
operations and a variety of cements are not good candidates for 
prescriptive requirements. One suggested approach was to supplement 
current cement compressive strength and height requirements with 
regulatory

[[Page 8404]]

guidelines that would allow the needed flexibility to determine which 
practices are applicable to the particular down-hole environment. 
Several commenters noted that they are participating in an API/
International Standards Organization (ISO) Cementing Committee to 
discuss best cementing practices with MMS and develop appropriate 
guidance for best cementing practices.
    Response: MMS will continue with the cementing requirements as 
proposed in this rule. These requirements are similar to the 
requirements that were in the previous regulations. As noted in the 
above comment, MMS is participating in the API/ISO Cementing Committee 
and will work with the committee to develop appropriate guidelines for 
cementing practices. We may take further regulatory actions after the 
committee completes its work.
    [sbull] Comment: One commenter said that the proposed regulations 
do not protect the environment enough, and that MMS is aware of a 
substantial number of OCS wells that are leaking oil to the surface and 
between formations. The commenter asserted that the proposed rule 
aggravates this problem by using the term ``cementing.'' The commenter 
asked why MMS allows oil companies to use cement and not other 
sealants.
    Response: MMS believes that the proposed regulations for cementing 
wells provide adequate protection to the environment. MMS also believes 
that there are opportunities to improve cements and cementing practices 
so, over the years, MMS has participated in a number of research 
projects that examined ways to improve cementing in oil and gas wells. 
We continue to participate in cementing research efforts and other 
efforts, such as the API/ISO Cementing Committee, to ensure that 
cementing technology continues to advance. MMS requires industry to use 
cement to seal formations and plug wells because it works; however, we 
will allow industry to use other sealants if they provide equal or 
better performance than cement. In the past, these generic requests to 
expand the rules to allow the use of other ``sealants'' have sometimes 
actually been attempts to get approval to use clays, gels, and other 
low compressive strength, non-hardening compounds.
    MMS knows of only a few abandoned wells that have leaked after 
permanent abandonment. When we become aware of an abandoned well that 
is leaking, we require the operator of record to take immediate action 
to remedy the situation. Also, to further our awareness of potential 
leaking abandoned wells, MMS has recently sponsored research to 
identify leaking abandoned wells by using remote sensing.
    [sbull] Comment on regulating coiled tubing drilling: The OOC 
commented that MMS was taking the correct approach by not proposing 
specific regulations for coiled tubing drilling. OOC agreed that a 
better understanding of these operations and the amount of activity 
that is likely to take place on the OCS was necessary before drafting 
regulations. OOC stated that the existing/proposed provisions in 
subpart D, coupled with the District Supervisors' authority to approve 
alternative techniques and procedures, adequately addresses the 
regulatory mandates. OOC also supported the use of API RP 5C7 for 
Coiled Tubing Operations in Oil and Gas Well Services (API RP 5C7) as a 
guideline when preparing the appropriate regulations.
    Response: MMS will continue to monitor the use of coil tubing on 
the OCS and will propose additional regulations as needed.

II. Comments on Specific Sections That the OOC Did Not Address in Its 
Comments

    [sbull] Comment on Sec.  250.404 What mobile drilling unit 
movements must I report? This requirement should be waived after 
commencement of the first well on a platform.
    Response: We have revised this section to clearly state what rig 
movements the lessee must report to MMS. This includes the movement of 
both mobile offshore drilling units (MODU) and platform rigs. We need 
this information to ensure that our inspectors have the correct 
information in hand when they arrive at a platform rig to perform an 
inspection. MMS also needs to know the movement of drilling rigs, 
coiled tubing units, and snubbing units on and off locations for 
completion and workover activities, so we will clarify these 
requirements in revisions of 30 CFR 250, subparts E and F that we 
anticipate proposing.
    [sbull] Comment on Sec.  250.404 What mobile drilling unit 
movements must I report? The proposed rule duplicates U.S. Coast Guard 
(USCG) requirements to report MODU movements under 33 CFR parts 67 and 
72. While the proposed rule affects the lessee, the MODU owner is 
reporting the required information to the USCG. MMS and USCG should 
share this information so that you can eliminate a reporting 
requirement.
    Response: MMS needs MODU movement information 24 hours in advance 
of movement to plan our rig inspections. USCG's timing requirements for 
rig movement notice do not meet our rig inspection planning needs. 
Based on similar comments during the process to develop the new MMS 
form to report rig movements, we incorporated ``optional'' information 
needed by the USCG so that the form could be used for reporting to 
either agency.
    [sbull] Comment on Sec.  250.412 What requirements must my plat 
meet? The lessee or operator should be allowed to decide how to report 
well location.
    Response: MMS must have the coordinates reported in a consistent 
manner to ensure that the exact well locations are known.
    [sbull] Comment on Sec.  250.417 What information must I provide if 
I intend to use a mobile drilling unit to drill a proposed well? 
Paragraph (c) may require a third-party review of a MODU's design by a 
Certified Verification Agent. This review may involve the MODU's 
structural components or integrity which would be in direct conflict 
with the December 1998 Memorandum of Understanding (MOU) between MMS 
and USCG. Under that MOU, the USCG has full responsibility for the 
structural integrity of MODUs.
    Response: This is not a new requirement (see current regulation at 
Sec.  250.401(a)(3)). The purpose of this requirement is to address the 
possible unique drilling unit that a lessee may propose to use in a 
frontier area. Our intent is to ensure that proper design reviews are 
conducted before the unit's use at a proposed frontier location. When 
this situation occurs, MMS will confer with the USCG concerning the 
drilling unit design and its use at the specified location. If the USCG 
design review meets our concerns, then MMS will not require additional 
design reviews. If additional reviews are needed, the District 
Supervisor will use this requirement to address necessary information. 
We have revised this paragraph to clarify that this requirement applies 
only to frontier areas where the drilling unit design is unique or the 
unit has not been proven for use in the proposed environment. MMS will 
follow the 1998 MMS/USCG MOU to the extent possible to minimize 
duplicating design requirements of both agencies.
    [sbull] Comments on Sec.  250.417(h) and 250.418(a). The IADC and 
two drilling contractors commented that these paragraphs indicate that 
MMS is maintaining files of rig-specific information. While such action 
by MMS is clearly in a drilling contractor's interest, they could not 
find the authority for MMS to maintain files on individual drilling 
rigs or to transfer this

[[Page 8405]]

information between the files of lessees/operators.
    The commenters were frustrated that MMS interprets its legislative 
authority as precluding direct contact between the agency and rig 
owners. They are convinced that direct communication between MMS and 
MODU owners/operators is permissible and advisable. They recommended 
that MMS should review and approve the use of MODUs and platform rigs 
on a regional basis. This would eliminate what appears to be a 
repetitive and non-productive review of identical drilling rig 
specifications by its District Offices.
    Response: The lessee/operator must submit a detailed description of 
the drilling unit including specifications for all its components, 
regardless of whether it is a MODU, with the Application for Permit to 
Drill (APD) a new well. MMS may communicate with the contractor; 
however, it is the responsibility of the lessee/operator to submit the 
required information to MMS. Drilling unit documents are part of the 
APD and are maintained in well data files by MMS.
    MMS does maintain limited files (work history, where and when 
built, depth capability and water depth, safe welding area approval, 
USCG certificate, etc.) on drilling rigs in the Gulf of Mexico (GOM). 
This information is useful as a cross reference of submitted 
information and when the lessee/operator does not include rig-specific 
information with the APD or sundry notice. Such information is used 
only within MMS (although much is readily available on the company Web 
sites) and is not transferred between lessees/operators. MMS only 
requires submission of this basic rig information and job-specific 
information such as BOP sketch, diverter sketch, and similar related 
information. This job-specific information can change due to rental 
BOPs and diverters or procedural changes.
    MMS drilling and workover engineers, as well as inspectors, 
regularly talk with rig owners, superintendents, pushers, drillers, and 
operator personnel about rig conditions, pollution, new equipment, 
training, accidents, etc. Only those items specific to a location, 
items that must be renewed regularly (certificates), and training are 
reviewed for each APD or sundry notice, and even some of these are only 
checked by the inspector once work has started. It is up to the lessee/
operator via their contracts to require that rig owners conform to MMS 
regulations.
    [sbull] Comment on Sec.  250.422(b) When may I resume drilling 
after cementing? A commenter said that the waiting time before removing 
the diverter is not necessary.
    Response: MMS disagrees. Determining the time when it is safe to 
remove the diverter is just as important as determining the time for 
the BOP because several incidents have involved early removal of the 
diverter.
    [sbull] Comment on Sec.  250.423(f) How must I remedy cementing and 
casing problems and irregularities? A commenter suggested that field-
specific rules rather than general rules should apply to the 
requirement that you must have at least two cemented casing strings to 
produce a well.
    Response: Field rules could apply if they are established in 
accordance with Sec.  250.463.
    [sbull] Comment on Sec.  250.424(b) What are the requirements for 
pressure testing casing? The requirement should allow an exception for 
horizontal cementing applications.
    Response: To obtain an exception for pressure testing casing, you 
may request approval from the District Supervisor to use alternative 
procedures (Sec.  250.408) or obtain a departure (Sec.  250.409). The 
District Supervisor will evaluate these requests on a case-by-case 
basis. Therefore, we did not include an exception for horizontal 
cementing applications in the requirements.
    [sbull] Comment on Sec.  250.430 When must I install a diverter 
system? MMS shouldn't require installation of a diverter when returns 
are taken at the ocean floor (i.e., no casing/riser on which to install 
a diverter).
    Response: The regulations require the installation of a diverter 
system before you drill a conductor or surface hole. If you want to 
drill a conductor or surface hole without a diverter, you must include 
this procedure in your APD and obtain approval from the District 
Supervisor.
    [sbull] Comment on Sec.  250.431 What are the diverter design and 
installation requirements? MMS should consider removing statements from 
the regulations that are not auditable, such as minimizing the number 
of turns or maximizing the radius of curvature of turns for diverter 
lines for bottom-founded drilling units. MMS could reference industry 
standards such as API RP 53 to better define what is required.
    Response: MMS will continue with the current performance standards 
of minimizing the number of turns and maximizing the radius of 
curvature of turns for diverter lines. We used these standards in past 
regulations because it is difficult to prescribe measures that will 
work for each drilling unit. However, in future rulemakings, we will 
consider incorporating additional standards to address some of the 
requirements that are difficult to audit.
    [sbull] Comment on Sec.  250.433 How must I test the diverter 
system after installation? MMS should allow for testing diverters on a 
14-day frequency.
    Response: MMS conducted several studies on BOP performance before 
we revised the regulations to allow for testing BOPs on a 14-day 
frequency. We made sure that extended testing frequency would not 
compromise safety during drilling operations. MMS will not consider 
revising the testing frequency for diverters until research shows that 
an extended testing frequency will not compromise safety.
    Comments on Sec.  250.441 What are the requirements for a surface 
BOP stack?
    This section proposed that each surface BOP stack must have at 
least one preventer equipped with blind-shear rams within 1 year after 
the effective date of this final rule. This proposed requirement 
prompted many comments. Four commenters opposed the proposed 
requirement and provided reasons for their opposition. IADC provided 
the most comprehensive comments against this proposed requirement. A 
fifth commenter stated that it also opposed the proposed requirement 
and said it supported IADC's comments. Three other commenters stated 
that they supported IADC's and OOC's comments but they did not 
specifically mention the proposed requirement for blind-shear rams. Two 
other commenters also provided comments on this proposed requirement 
and those comments are included below.
    A summary of all the comments on the proposed requirements for 
blind-shear rams follows:

--IADC plotted the incidents over the 20-year period, and its graph 
showed that the incident rate where blind-shear rams might have 
prevented a serious blowout is approaching zero. IADC believes that 
this trend is sufficient to negate the need for MMS to mandate the 
installation of the blind-shear rams. Possible activities that lead to 
this declining trend include:

    [sbull] Greater attention being paid to safety management as a 
result of Safety and Environmental Management Programs and other 
initiatives;
    [sbull] Continuous improvement in well control methods and 
equipment; and
    [sbull] Greater attention to the quality of well control training

--IADC also stated the following:


[[Page 8406]]


    [sbull] Successful operation of blind-shear rams (intentional or 
not) permanently forecloses other well control options;
    [sbull] MMS did not consider the consequences of inadvertent 
operation or malfunction of the rams;
    [sbull] MMS underestimated the number of surface BOP stacks that 
would need blind-shear rams by 50 percent, thus underestimating the 
costs by 50 percent; and
    [sbull] If the final rule requires the blind-shear rams, then 
industry will need an additional 2 years to comply with the 
requirement.

--Operating limits of blind-shear rams are frequently unclear for some 
drilling operations due to pipe grades, mud weights, and wellbore 
pressures, and that consideration should be given to ensure that these 
limits are clear

    Response: MMS continues to believe that having blind-shear rams in 
a surface BOP stack is an important safety measure. Blind-shear rams 
offer an additional opportunity to control the well in a difficult 
situation. We believe that these rams provide the last line of defense 
against a blowout when drill pipe or tubing is hung in the BOP stack 
and there are difficulties in installing or closing the drill string 
safety valve, inside BOP, or tubing safety valve. Successful operation 
of the blind-shear rams may prevent damage to the drilling rig, 
platform, or other facilities, and prevent injuries or the loss of 
life.
    The IADC and industry provided a number of comments on why MMS 
should not require blind-shear rams in surface BOP stacks. Their most 
compelling reason against requiring blind-shear rams is industry's 
recent performance concerning incidents where blind-shear rams might 
have prevented or minimized a blowout. Those comments are correct in 
that industry's recent performance is good, especially when compared to 
the relatively high number of incidents that occurred in the early 
1980's. However, there have been three serious incidents where blind-
shear rams may have prevented a blowout since 1996 (two incidents 
occurred in 2001). A brief description of each event follows:
    Incident 1--occurred on Platform A, Eugene Island Block 380, on 
January 24, 1996. During completion operations, the well began to flow 
while the tubing was extended above the BOP stack. The crew tried to 
stab the top drive into the top of the tubing but the flow had 
increased and they were unable to make the connection. The driller 
closed the blind rams to reduce the flow but that did not help. Gas 
began to flow out of the top of the tubing, so the drilling crew closed 
the pipe rams and annular preventer and evacuated the rig floor. During 
the evacuation of the rig and platform, the well caught fire. The fire 
destroyed the rig substructure and derrick and severely damaged other 
parts of the rig. Fortunately there were no injuries or pollution. 
After investigating the accident, MMS' investigation team recommended 
that blind-shear rams should be required in surface BOP stacks. The 
investigation report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/98-0012.pdf.
    Incident 2--occurred on Platform A Eugene Island Block 277, on July 
6, 2001. While killing a kick that occurred during workover operations, 
the pressure safety valve on the mud pump ruptured. The well then 
flowed uncontrolled through the drill pipe and the ruptured pressure 
safety valve. The area around the rig equipment and drill floor became 
inundated with a hazardous accumulation of gas and formation sand which 
forced all personnel to evacuate to a standby boat. Fortunately there 
were no injuries and only major damages to the rig. The investigation 
report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/2002-040.pdf.
    Incident 3--occurred on a jack-up drilling rig drilling in Brazos 
Block 417 on July 13, 2001. During drilling operations, the well began 
to flow while the crew was making up the next joint of drill pipe in 
the mouse hold. The rig floor safety valve was stabbed but would not 
close with two men applying torque to the handle. Both men were burned 
on their arms and back by the hot mud. Because of the high temperature 
of the mud, the men had to put on slicker suits and were sprayed with 
water to continue working on the rig floor. A third man assisted in the 
attempt to close the valve and sufficient torque was applied to the 
closing handle to shear it off at the key opening of the valve. Mud 
continued flowing out of the drill pipe until it was shooting over the 
the top of the derrick. Gas began to flow with the mud from the drill 
pipe and it became unsafe to work on the rig floor. The crew was 
ordered to abandon the rig. After the rig was abandoned, it was 
discovered that the night supervisor was missing. The Coast Guard 
searched for two days but the night supervisor was never found. The BOP 
stack, casing and drill pipe were damaged by high pressure gas and sand 
that flowed from the well. The rig was also damaged by the gas and sand 
flow. The investigation report can be found on our Web site at: http://www.gomr.mms.gov/homepg/offshore/safety/acc_repo/2002-062.pdf.
    In these incidents, the drilling crews had run out of options to 
control the well and were forced to abandon the rig. We believe that 
the injuries, the fatality, and rig damages could have been avoided if 
blind-shear rams were in the BOP stack and were closed prior to 
evacuating the rig. Similar incidents have occurred during drilling, 
workover, and completion operations in the past, and blind-shear rams 
stopped the blowout. Similar incidents are very likely to occur in the 
future.
    In the preamble of the proposed rule, MMS stated that it had 
reviewed the blowouts that have occurred since 1977 and found at least 
12 incidents where blind-shear rams had helped or could have helped 
control the situation. Upon closer review of our records, we have 
identified 24 incidents where blind-shear rams either helped control a 
blowout or may have helped prevent a blowout (these records include 
MMS's database, memoranda, accident reports, investigations, operator 
letters, and operator investigations). The table below gives the date, 
location, and a brief description of each of those incidents. There 
were 10 fatalities, 23 injuries, 3 rigs destroyed, and 9 rigs damaged 
during those incidents. Furthermore, six of the investigation reports 
recommended that blind-shear rams be installed in surface BOP stacks. 
Considering that the installation of blind-shear rams provides an 
additional means of controlling a blowout and can help prevent future 
injuries, fatalities, and protect property and the environment, MMS 
will require the installation of blind-shear rams in surface BOP 
stacks.

----------------------------------------------------------------------------------------------------------------
            Date                            Block/lease                     Description of incident
----------------------------------------------------------------------------------------------------------------
6/23/77.....................  Eugene Island 307, G 2110........................  Blowout while running dual
                                                                                  completion string. Tubing was
                                                                                  84 feet above the drill floor
                                                                                  when well began blowing
                                                                                  through the tubing. The tubing
                                                                                  safety valve could not be
                                                                                  installed so blind rams were
                                                                                  closed but only crimped the
                                                                                  tubing. Crew evacuated the rig
                                                                                  safely. The blowout was
                                                                                  controlled later that day. The
                                                                                  Investigation Report
                                                                                  recommended that the U.S.
                                                                                  Geological Survey require
                                                                                  shear rams on all BOP stacks.

[[Page 8407]]

 
7/20/77.....................  West Cameron 110, OCS 081........................  Blowout occurred during
                                                                                  workover operations. Well
                                                                                  began to flow while pulling
                                                                                  out of the hole. Drill string
                                                                                  safety valve was installed but
                                                                                  could not be closed. Blind
                                                                                  rams were closed to restrict
                                                                                  the flow but had no effect.
                                                                                  There were no injuries. Well
                                                                                  Control Team secured well 4
                                                                                  days later.
11/26/77....................  Eugene Is. 307 G, 2110...........................  Well blew out while running
                                                                                  into the hole during
                                                                                  completion operations. All of
                                                                                  the BOP's were closed but the
                                                                                  well continued to flow. The
                                                                                  flow was too great to stab the
                                                                                  drill string safety valve.
                                                                                  After 6 hours of attempting to
                                                                                  diminish the flow through the
                                                                                  drill pipe, the crew was able
                                                                                  to install and close the drill
                                                                                  string safety valve.
8/4/78......................  Grand Isle 41, G 0129............................  Blowout occurred during
                                                                                  completion operations. Drill
                                                                                  string safety valve could not
                                                                                  be closed after well began to
                                                                                  flow. After 15 minutes, the
                                                                                  driller regained control of
                                                                                  the well by closing blind-
                                                                                  shear rams. There were no
                                                                                  injuries.
3/5/79......................  S. Marsh Island 281, G 2600......................  While attempting to correct
                                                                                  lost returns and stuck pipe
                                                                                  problems, the well began to
                                                                                  flow. The crew could not close
                                                                                  the drill string safety valve
                                                                                  when the well kicked the final
                                                                                  time. There were eight
                                                                                  fatalities and considerable
                                                                                  damage to rig. The USCG
                                                                                  Investigation Report (Oil &
                                                                                  Gas Journal, p. 148, Nov. 17,
                                                                                  1980) concluded that shear
                                                                                  rams could prevent similar
                                                                                  casualties in the future.
8/24/80.....................  Vermilion 348, G 2271............................  The well kicked while making up
                                                                                  gravel pack assembly. The
                                                                                  blind and pipe rams were
                                                                                  closed on 4\1/2\'' pipe
                                                                                  portion of gravel pack
                                                                                  assembly but did not seal the
                                                                                  well. The drilling rig and
                                                                                  portion of platform were
                                                                                  destroyed. There were four
                                                                                  minor injuries in the crew
                                                                                  evacuation. The well bridged
                                                                                  37 days later.
1/12/81.....................  High Island 38, G 0477...........................  Blowout occurred while
                                                                                  circulating out a kick. The
                                                                                  well blew out through the neck
                                                                                  on the swivel. The lower kelly
                                                                                  cock was left 12 feet above
                                                                                  the drill floor and was not
                                                                                  closed. The blowout lasted
                                                                                  approximately 12 hours,
                                                                                  catching fire towards the end
                                                                                  of the incident. Three people
                                                                                  suffered overexposure after
                                                                                  the evacuation and one later
                                                                                  died.
7/26/81.....................  South Pelto 18, G3589............................  Blowout during completion
                                                                                  operations. While circulating
                                                                                  mud, the well kicked. Crew
                                                                                  closed upper kelly cock but it
                                                                                  leaked. Operator closed blind-
                                                                                  shear rams and evacuated
                                                                                  platform. Gas leaked through
                                                                                  the blind-shear rams but the
                                                                                  rig never caught fire. Well
                                                                                  was controlled 4 days later.
                                                                                  One person suffered a broken
                                                                                  leg and bruises during the
                                                                                  evacuation.
10/5/81.....................  Eugene Island 273, G 0987........................  Blowout occurred when the
                                                                                  tubing parted during
                                                                                  completion operations. The
                                                                                  well was controlled after 38.5
                                                                                  hours by installing and
                                                                                  closing blind-shear rams. The
                                                                                  Investigation Report
                                                                                  recommended that BOP stacks
                                                                                  have blind-shear rams for
                                                                                  completion operations. There
                                                                                  were no injuries during the
                                                                                  evacuation.
11/28/81....................  Viosca Knoll 900, G 2445.........................  Blowout occurred during
                                                                                  workover operations. The well
                                                                                  kicked while pulling out of
                                                                                  the hole. The BOPs were
                                                                                  closed, but the flow through
                                                                                  the drill string was too great
                                                                                  to stab the drill string
                                                                                  safety valve. The blowout
                                                                                  lasted 24 hours. There was
                                                                                  some pollution but no injuries
                                                                                  and minimal damages.
4/19/82.....................  Galveston 391, G 3740............................  Blowout occurred while
                                                                                  completing the well. A drill
                                                                                  string safety valve could not
                                                                                  be installed because the drill
                                                                                  pipe was above the monkey
                                                                                  board. Well bridged over in 3
                                                                                  hours. There were no injuries
                                                                                  and only minimal damage to the
                                                                                  platform and rig.
5/15/82.....................  S. Marsh Island 155, G 4110......................  While circulating a kick, an
                                                                                  explosion and fire occurred
                                                                                  under the rig floor and at the
                                                                                  shale shaker. Blind-shear rams
                                                                                  were activated and the well
                                                                                  was shut in. Three people
                                                                                  suffered minor injuries during
                                                                                  the evacuation.
7/14/82.....................  West Cameron 65, G 2825..........................  Fishing operation when well
                                                                                  began to kick. While
                                                                                  attempting to control kick,
                                                                                  the stand pipe blew out and
                                                                                  the drilling crew could not
                                                                                  close either of the kelly
                                                                                  valves. Jackup rig was
                                                                                  destroyed and the blowout
                                                                                  continued for 57 days. There
                                                                                  were no injuries.
12/17/82....................  West Delta 70, G 0182............................  Blowout occurred while working
                                                                                  over well with a snubbing
                                                                                  unit. Blowout pushed top of
                                                                                  workstring to a point 30 feet
                                                                                  above the highest object on
                                                                                  the platform. Blowout was
                                                                                  stopped after repeated
                                                                                  attempts to function the shear
                                                                                  rams.
10/20/83....................  Eugene Island 10, G 2892.........................  While controlling a kick during
                                                                                  a workover, gas began to leak
                                                                                  from the threads in the
                                                                                  crossover sub and the drill
                                                                                  string safety valve. The leak
                                                                                  increased as the valve was
                                                                                  closed, forcing the
                                                                                  abandonment of the rig. The
                                                                                  well was killed 6 days later.
                                                                                  There was major damage to the
                                                                                  rig but no injuries.
12/3/85.....................  West Cameron 648, G 4268.........................  Blowout during workover. Crew
                                                                                  unable to stab workstring
                                                                                  safety valve into the
                                                                                  workstring when fluid began
                                                                                  flowing. Three people were
                                                                                  injured trying to stab the
                                                                                  safety valve. The rig was
                                                                                  destroyed and the platform
                                                                                  heavily damaged by fire. The
                                                                                  blowout lasted 47 days. The
                                                                                  Investigation Report
                                                                                  recommended that Order 6 be
                                                                                  revised to require blind-shear
                                                                                  rams in BOP stack during
                                                                                  workovers.
3/20/87.....................  Vermilion 226, G 5195............................  Blowout during completion
                                                                                  activities. Blowout through
                                                                                  the drill pipe and drill
                                                                                  string safety valve failed.
                                                                                  The well control team killed
                                                                                  the well by installing blind-
                                                                                  shear rams and shutting in the
                                                                                  well. There were no injuries
                                                                                  and only minor damage during
                                                                                  the 3-day blowout. The
                                                                                  Accident Investigation Report
                                                                                  recommended the installation
                                                                                  of blind-shear rams in BOP
                                                                                  stacks.
5/30/90.....................  Brazos A-23, G 3938..............................  Blowout occurred during testing
                                                                                  operations. The blind-shear
                                                                                  rams were closed but failed as
                                                                                  the rig was being jacked up to
                                                                                  clear tubing from the blind
                                                                                  rams. Blind rams were closed
                                                                                  but gas flowed until well
                                                                                  control team killed the well.
                                                                                  There were no injuries and
                                                                                  only minor damages during the
                                                                                  2-day blowout.
9/9/90......................  Eugene Island 296, G 2105........................  During workover operations,
                                                                                  well began to flow through
                                                                                  tubing after running one stand
                                                                                  of collars and one stand of
                                                                                  tubing into the well. Crew
                                                                                  made at least four
                                                                                  unsuccessful attempts to
                                                                                  install full opening safety
                                                                                  valve. The BOPs were closed
                                                                                  but did not stop the blowout.
                                                                                  There were eight injuries and
                                                                                  rig damage during the 4-day
                                                                                  blowout.

[[Page 8408]]

 
1/24/96.....................  Eugene Island 380, G 2327........................  During completion operations,
                                                                                  the well began to flow while
                                                                                  the tubing was extended above
                                                                                  the BOP stack. Crew tried to
                                                                                  stab the top drive into the
                                                                                  top of the tubing but the flow
                                                                                  prevented the connection. The
                                                                                  driller closed the blind rams
                                                                                  to reduce the flow but that
                                                                                  did not help. When gas began
                                                                                  to flow out of the top of the
                                                                                  tubing, the drilling crew
                                                                                  closed the pipe rams and
                                                                                  annular preventer and
                                                                                  evacuated the rig. During the
                                                                                  evacuation of the rig and
                                                                                  platform, the well caught
                                                                                  fire. Fire destroyed the rig
                                                                                  substructure and derrick and
                                                                                  severely damaged other parts
                                                                                  of the rig. MMS investigation
                                                                                  report recommended that blind-
                                                                                  shear rams be required in
                                                                                  surface BOP stacks. (incident
                                                                                  1 in above discussion).
5/31/97.....................  East Cameron 83, G 8641..........................  Blowout during completion
                                                                                  operations. Well control team
                                                                                  replaced pipe rams with blind-
                                                                                  shear rams but found that the
                                                                                  tool joint was opposite the
                                                                                  rams. There were no injuries,
                                                                                  pollution, or fire. Well was
                                                                                  out of control for 19 days.
12/2/99.....................  SM58, G 01194....................................  Blowout occurred while running
                                                                                  a gravel pack assembly during
                                                                                  completion activities. The
                                                                                  gravel pack was across the BOP
                                                                                  stack when the well began to
                                                                                  flow. The BOP's were closed
                                                                                  but did not stop the blowout.
                                                                                  The well bridged over the next
                                                                                  day.
7/6/01......................  Eugene Island 277, OCS-G 10744...................  Blowout occurred during a
                                                                                  workover operation. Well
                                                                                  flowed uncontrolled through
                                                                                  the drill pipe and ruptured
                                                                                  pressure safety valve on the
                                                                                  mud pump. The area around the
                                                                                  rig equipment and drill floor
                                                                                  became inundated with a
                                                                                  hazardous accumulation of gas
                                                                                  and formation sand thus
                                                                                  forcing all personnel to
                                                                                  evacuate to a standby boat.
                                                                                  There were no injuries and
                                                                                  only minor damages to the rig.
                                                                                  (incident 2 in above
                                                                                  discussion).
7/13/01.....................  Brazos 417, OCS-G 22190..........................  Blowout occurred during
                                                                                  drilling operations. The well
                                                                                  kicked and flowed up the drill
                                                                                  pipe. The rig floor safety
                                                                                  valve was stabbed but would
                                                                                  not close with two men
                                                                                  applying torque to the handle.
                                                                                  Both men were burned on their
                                                                                  arms and back by the hot mud.
                                                                                  Because of the high
                                                                                  temperature of the mud, the
                                                                                  men had to put on slicker
                                                                                  suits and were sprayed with
                                                                                  water to continue working on
                                                                                  the rig floor. The crew was
                                                                                  ordered to abandon the rig.
                                                                                  After the rig was abandoned,
                                                                                  it was discovered that the
                                                                                  night supervisor was missing.
                                                                                  The Coast Guard searched for
                                                                                  two days but the person was
                                                                                  never found. The BOP stack,
                                                                                  casing and drill pipe were
                                                                                  damaged by high pressure gas
                                                                                  and sand that flowed from the
                                                                                  well. The rig was also damaged
                                                                                  by the gas and sand flow.
                                                                                  (incident 3 in above
                                                                                  discussion).
----------------------------------------------------------------------------------------------------------------

    IADC commented that we underestimated the number of blind-shear 
rams by approximately 50 percent (80), thus underestimating the costs 
by 50 percent. We have reexamined the number of rams that industry 
would have to purchase and found that of the rigs currently active or 
ready to work, 100 surface BOP stacks did not have blind-shear rams. 
When rigs temporarily taken out of service are included, 170 sets of 
blind-shear rams would be needed. Part of our low estimate was due to 
the increased drilling activity since we prepared the proposed rule and 
part was due to a low estimate of the number of blind-shear rams 
already installed in surface BOP stacks. Our recent review found that 
at least 30 sets of blind-shear rams are currently installed in surface 
BOP stacks.
    MMS made two assumptions when estimating the cost of upgrading 
existing surface BOP stacks to include blind-shear rams. First, it was 
projected that all rigs active or ready to work would remain in service 
for more than the next 3 years. Second, one-half of the rigs 
temporarily taken out of service would be placed back into long term 
service over the next 3 years. Increasing the number of blind-shear 
rams needed to comply with this requirement to 135 sets will raise 
costs estimated in the proposed rule from $14,000,000 to $14,175,000. 
The original cost per set of blind-shear rams was overstated 
($175,000), and has been reduced ($105,000) according to information 
obtained recently from BOP manufacturers. Given the number of rams that 
industry will have to purchase, MMS has allowed a 3-year timeframe for 
installing the rams versus the 1-year timeframe identified in the 
proposed rule. This 3-year period will allow industry sufficient time 
to plan the acquisition and installation of this critical safety 
equipment. The following table summarizes the costs associated with 
this requirement.

----------------------------------------------------------------------------------------------------------------
                                                                                                   Cost to small
                Requirement                    Total cost                Annual costs               businesses
----------------------------------------------------------------------------------------------------------------
Proposed Rule--Install blind-shear rams          $14,000,000  $14,000,000 over 1 year...........              $0
 within 1 year.
Final Rule--Install blind-shear rams              14,175,000  4,725,000 over 3 years............               0
 within 3 years.
----------------------------------------------------------------------------------------------------------------

    Avoidance of future blowout related costs, through the installation 
of blind-shear rams on all existing drilling rigs with surface BOP 
stacks, would constitute the potential benefits to lessees and their 
drilling contractors. In the analysis conducted for this rule, gross 
benefits are partially offset by the costs to purchase and install 
blind-shear rams, in surface BOP stacks that don't already have them. 
Our analysis indicates that implementation of the regulation will most 
likely result in net present value benefits to lessees and drilling 
contractors of $22 million. These benefits can be achieved by investing 
in the acquisition and installation of blind-shear rams for a present 
value cost of $13 million. Accordingly, the present value of gross 
industry benefits from this regulation will most likely be $35 million.
    As discussed in the proposed rule, we believe that the final rule 
will not have a significant impact on small drilling contractors. It 
won't impact small drilling contractors because there is only one that 
qualifies as a small business, and that contractor has already equipped 
its surface BOP stacks with blind-shear rams. The drilling contractor 
indicated that the blind-shear rams were installed as an additional 
safety precaution.
    IADC also commented that MMS did not consider the consequences of 
the

[[Page 8409]]

inadvertent operation or malfunction of the blind-shear rams in the 
proposed rule. We know industry has many years of experience with 
having blind-shear rams in subsea BOP stacks and that industry has 
developed safeguards and procedures to prevent the inadvertent 
operation of this equipment. Also, several operators have many years of 
experience of having blind-shear rams in surface BOP stacks in the GOM. 
MMS, therefore, is confident that industry can adequately safeguard the 
BOP control panels and adequately train its personnel to prevent the 
inadvertent operation of blind-shear rams.
    MMS disagrees with IADC's comment that the successful operation of 
blind-shear rams permanently forecloses other well control options. 
Many wells have been controlled after blind-shear rams shut them in. At 
least four of the wells identified in the table above regained control 
of the well by lubricating heavyweight drilling fluids into the annulus 
to kill the well (8/4/78; 10/5/81; 5/15/82; 3/20/87). While lubricating 
or bullheading fluids into a live well may not be the preferred method 
for regaining control of a well, it is better than losing total control 
of the well.
    Finally, one commenter indicated that the operating limits of 
blind-shear rams are frequently unclear for some drilling operations 
due to pipe grades, mud weights, and wellbore pressures, and that 
consideration should be given to ensure that these limits are clear. We 
agree that this is important, so we have added a paragraph to Sec.  
250.416(e) that requires the lessee to address these issues. The new 
paragraph requires the lessee to provide information that shows that 
the blind-shear or shear rams installed in the BOP stack (both surface 
and subsea stacks) are capable of shearing the drill pipe in the hole 
under maximum anticipated surface pressures.
    [sbull] Comment on Sec.  250.441 What are the requirements for a 
surface BOP stack? MMS should revise the rule to allow an exception for 
less than four remote-controlled BOPs.
    Response: Because you may include this request in your APD 
submission to the District Supervisor, we did not revise the rule to 
allow the use of less than four remote-controlled BOPs in certain 
situations.
    [sbull] Comment on Sec.  250.442 What are the requirements for a 
subsea BOP stack? One commenter asked why didn't MMS identify the costs 
associated with the subsea accumulator requirements.
    Response: MMS did not specify any costs for this requirement 
because lessees/operators were already required by the regulations to 
have an accumulator that provided for fast closure. API RP 53 now 
provides guidelines for determining the minimum requirements and 
performance for the subsea accumulator.
    [sbull] Comment on Sec.  250.442 What are the requirements for a 
subsea BOP stack? A commenter noted that section 13.3 of API RP 53 does 
not include subsea accumulator volume requirements that can be audited 
other than the specific response times.
    Response: MMS will review BOP test records, including documentation 
of the closing times of ram and annular preventers, in evaluating BOP 
system performance.
    [sbull] Comment on Sec.  250.443 What associated BOP systems and 
related equipment must my BOP system include? MMS should clarify that 
this section applies to both surface and subsea BOP equipment. The 
commenter also recommended that MMS consider adopting more sections of 
API RP 53 and/or API RP 16E instead of having a number of the specific 
requirements stated in the BOP system sections (250.440 to 250.451). 
Adoption of these documents would provide a more rigorous standard than 
the current MMS requirements.
    Response: We clarified the intent of this section by revising the 
title to read ``What associated BOP systems and related equipment must 
my surface and subsurface BOP systems include?'' MMS will consider 
incorporating additional sections of API RP 53 and API RP 16E or 
possibly the entire document in possible future revisions of the 
drilling regulations.
    [sbull] Comment on Sec.  250.446 What must I do to maintain and 
inspect my BOP? MMS should consider incorporating parts of other 
quality management standards into the regulations, such as API Q1's, 
``The supplier shall establish and maintain documented procedures for 
implementing corrective and preventive action * * * and API Spec 16A's, 
Appendix G, ``The operator of drill through equipment manufactured to 
this specification shall provide a written report to the equipment 
manufacturer of any malfunction or failure which occurs * * *''
    Response: The quality management program incorporated by sections 
17.12 and 18.12 in API RP 53 pertains to a planned maintenance system 
for BOP equipment and to maintaining copies of equipment manufacturer's 
product alerts and bulletins. The purpose for incorporating these 
sections was to ensure that BOP equipment is maintained properly. It 
was not to require equipment specifications or certification 
requirements for BOP equipment. MMS believes that incorporation of the 
specific sections of API RP 53 will meet the objective of identifying 
appropriate maintenance requirements.
    [sbull] Comment on Sec.  250.448 What are the BOP pressure tests 
requirements? MMS requirements for a low-pressure test provide a lower 
acceptance standard when compared to sections 17.3.2 and 18.3.2. MMS 
should consider incorporating these sections into the regulations.
    Response: These sections of API RP 53 state the following on low-
pressure tests: ``When performing the low pressure test, do not apply a 
higher pressure and bleed down to the low test pressure. The higher 
pressure could initiate a seal that may continue to seal after the 
pressure is lowered and, therefore, misrepresenting a low pressure 
condition.'' MMS recognizes that this situation could occur on a low-
pressure test, but we also recognize that it may be difficult to 
precisely apply 200 to 300 pounds per square inch (psi) to the 
component to be tested. Based on our experience and judgment, we have 
allowed operators to conduct a low-pressure test (200 to 300 psi) if 
the initial pressurization did not exceed 500 psi. Any pressure higher 
than 500 psi must be bled to zero and the test reinitiated.
    [sbull] Comment on Sec.  250.448 What are the BOP pressure tests 
requirements? MMS should consider testing ram preventers at an 
intermediate pressure, which ranges between 2,000 and 4,500 psi 
depending on closing ratio, because it provides a better measure of 
fitness for purpose. This intermediate pressure is another possible 
mode of failure. These intermediate pressure tests would be conducted 
initially and on an annual basis.
    Response: MMS is unlikely to require such a test until it becomes 
an accepted industry practice.
    [sbull] Comment on Sec.  250.449 What additional BOP testing 
requirements must I comply with? The requirement for variable bore rams 
(VBRs) to pressure test against all sizes of pipe may be more rigorous 
than the largest and smallest sizes as recommended by API RP 53 
(sections 17.5.5 and 18.5.5).
    Response: We have revised the requirement in Sec.  250.449(f) to 
now require you to pressure test VBRs against the largest and smallest 
sizes of pipe in use, excluding drill collars and bottom-hole tools. 
This conforms to API RP 53 recommended practice. Also, one of the 
findings from a 1999 research project, ``Reliability of Subsea BOP 
Systems for Deepwater Application, Phase II DW, by Per Holand of SINTEF 
Industrial Management,'' recommended

[[Page 8410]]

that we should not require testing VBRs on all sizes. The rationale was 
that the testing of VBRs on all sizes adds very little to increased 
safety availability in the BOP due to the redundancy in the stack, and 
that most failures will occur during the pressure test.
    [sbull] Comment on Sec.  250.449 What additional BOP testing 
requirements must I comply with? Mandatory pressure testing of the BOP 
system after landing is not justified considering the extremely low 
failure rate of BOP components and the fact that the physical act of 
running the stack imposes little to no stress on the functional 
components of the BOP system. After a successful stump test, MMS should 
require only a function test for the BOP stack once it is on bottom. 
Function testing after landing will ensure that all control circuits 
are operating properly. This minor revision has a potentially huge 
beneficial impact by saving lost rig time to the initial BOP pressure 
test.
    Response: We did not revise this requirement as suggested. We 
believe that the initial pressure test of the BOP stack after landing 
on the well is critical to ensuring that it functions properly. The 
results from our 1999 research project on the reliability of deep water 
subsea BOP systems (Holand, 1999) support our belief. That research 
project examined data from 83 wells that were drilled using subsea BOP 
stacks in the deep water GOM. The majority of the wells were spudded 
during July 1, 1997, to May 1, 1998. The results showed that 15 
components failed during the initial pressure tests after the BOP stack 
landed on the wellhead. Of those 15 failures, 10 were in the control 
systems and may have been discovered in a function test. However, five 
other failures occurred (two connectors, one annular preventer, one ram 
preventer, one choke and kill valve) that may not have been discovered 
without the initial pressure test. MMS will continue to require the 
initial pressure test after landing the subsea BOP stack.
    [sbull] Comment on Sec.  250.456 What are the required safe 
drilling fluid program practices? Paragraph (a) should not require 
circulating the well before starting out of the hole if you have lost 
circulation.
    Response: MMS believes that pipe should not be pulled out of the 
hole until a loss circulation pill has been spotted and the well is 
under control. It is recommended that the top part of the hole be 
circulated to ensure that the wellbore is clear of gas. Some loss of 
returns is acceptable while pulling out of the hole; however, excessive 
loss circulation would require remaining on bottom until the loss was 
controlled either with a pill or cement.
    [sbull] Comment on Sec.  250.456 What are the required safe 
drilling fluid program practices? Recommend that MMS eliminate the 
second sentence in paragraph (e) which says ``You must circulate and 
condition the well, on or near-bottom, unless well or drilling-fluid 
conditions prevent running the drill pipe back to the bottom.'' The 
first sentence of this requirement which says you must take appropriate 
measures to control the well is sufficient to address this situation.
    Response: We did not remove the second sentence of this paragraph 
because this is a safe drilling practice. However, the sentence in 
question does allow for not running drill pipe to bottom to circulate 
the well if conditions prevent it.
    [sbull] Comment on Sec.  250.456 What are the required safe 
drilling fluid program practices? Recommend that paragraph (f) allow 
the District Supervisor the discretion to not require the posting of 
the surface pressure at which the shoe would break down.
    Response: We did not revise this paragraph. You may request a 
departure from this requirement in your APD submission to the District 
Supervisor.
    [sbull] Comment on Sec.  250.456 What are the required safe 
drilling fluid program practices? MMS should allow the District 
Supervisor the discretion to not require degassers in all situations 
(paragraph (g)).
    Response: We did not revise this paragraph. You may request a 
departure from this requirement in your APD submission to the District 
Supervisor.
    [sbull] Comment on Sec.  250.458 What quantities of drilling fluids 
are required? The commenter prefers the current wording over the 
proposed wording.
    Response: The new regulations use a more active style of writing 
versus the passive style used in the previous regulations. The 
requirements (and most of the words) are the same.
    [sbull] Comments on Sec.  250.459 What are the safety requirements 
for drilling-fluid-handling areas? The two drilling contractors and 
IADC commented that the requirement to classify drilling-fluid-handling 
areas according to API RP 500, Recommended Practice for Classification 
of Locations for Electrical Installations at Petroleum Facilities, is 
in conflict with the 1998 MMS/USCG MOU as it relates to MODUs. The MOU 
assigns regulatory oversight of this subject matter to the USCG. USCG 
regulations at 46 CFR 108.170 and 108.187 clearly address these 
matters, as do the Classification Society requirements applicable to 
MODUs. Accordingly, the requirements in this section should not apply 
to MODUs.
    Response: This is not a new requirement. The USCG is responsible 
for the inspection on this area for electrical requirements; it is 
classified due to a possible source for gas coming out of the cuttings. 
MMS inspects for gas detectors and tests them on a regular basis. If we 
see anything that does not meet the USCG's requirement, such as an 
exposed wire, then MMS would shut down operation and require that it be 
repaired. All drilling-fluid-handling areas are treated the same.
    [sbull] Comment on Sec.  250.460 What are the requirements for well 
testing? These requirements should not apply if a well test is 
conducted on a permanent production facility.
    Response: Your projected plans for a well test on a permanent 
production facility must address all appropriate requirements. You may 
reference another document or plan if it addresses a specific 
requirement, such as the description of safety equipment.
    [sbull] Comment on Sec.  250.465 When must I submit sundry notices 
to MMS? An open hole sidetrack to go around junk in the hole and to 
continue drilling to the original approved APD should not require a 
sundry notice.
    Response: All sidetracks require the submittal of a sundry notice, 
and the API number is incremented. This allows the logs to be tracked 
and handled correctly.

III. OOC Comments on Specific Sections

    The following table contains the OOC's unedited comments on the 
proposed requirements for oil and gas drilling operations and our 
response to those comments. In this table, we have italicized words 
that OOC wanted added to the regulations and have bracketed words that 
the OOC wanted deleted from the regulations.

[[Page 8411]]



----------------------------------------------------------------------------------------------------------------
        Proposed section                OOC comments              OOC rationale               MMS response
----------------------------------------------------------------------------------------------------------------
250.198........................  Incorporate correct        By Federal Register        The final rule references
                                  editions of API RP 500     Notice dated January 4,    the correct documents
                                  and API RP 505 into the    2000, MMS incorporated     and editions.
                                  regulations.               by reference API RP 500,
                                                             Second Edition and API
                                                             RP 505, First Edition.
                                                             Proposed Rule should be
                                                             modified to state such.
250.401(b).....................  (b) Have a person onsite   Include 24 hours a day to  We did not add the 24
                                  24 hours per day during    provide clarity.           hours per day because it
                                  operations that                                       is unnecessary, but we
                                  represents your                                       did add during
                                  interests and can                                     operations as suggested.
                                  fulfill your
                                  responsibilities.
250.401(c).....................  (c) Ensure that the        Well may go from drilling  We made the suggested
                                  toolpusher or a member     to completion and not be   changes.
                                  of the drilling crew       abandoned. Additionally,
                                  maintains continuous       bridge plugs and cement
                                  surveillance of the rig    plugs are viable options
                                  floor from the beginning   for securing the well.
                                  of drilling operations
                                  until the well is
                                  abandoned or completed,
                                  unless you have secured
                                  the well with blowout
                                  preventers (BOPs),
                                  bridge plugs, cement
                                  plugs, or packers.
250.402........................  When and how must I        The use of the phrase      We made the suggested
                                  secure a well? Whenever    ``as deep as possible''    changes.
                                  you interrupt drilling     infers that the device
                                  operations, you must       should be set at the
                                  install a downhole         bottom of the hole. By
                                  safety device, such as a   changing ``as deep as
                                  cement plug, bridge        possible'' to ``an
                                  plug, or packer. You       appropriate depth''
                                  must install the the       allows the operator
                                  device [as deep as         flexibility to choose
                                  possible] at an            appropriate setting
                                  appropriate depth within   depths.
                                  a properly cemented
                                  casing string or liner.
250.402(a).....................  (a) [Among] The events     The proposed text          We did not make the
                                  that may cause you to      regarding what types of    suggested change because
                                  [interrupt] temporarily    events require securing    there may be other
                                  suspend drilling           of well downhole is        events that cause you to
                                  operations or.             vague and open-ended.      interrupt drilling
                                                             Therefore, we recommend    operations. The wording
                                                             the word ``among'' in      as suggested would limit
                                                             paragraph (a) be           the events that would
                                                             deleted, and the           require the installation
                                                             remainder of the           of a downhole safety
                                                             paragraph be amended as    device.
                                                             recommended to detail
                                                             the specific type of
                                                             events, which is
                                                             consistent with existing
                                                             requirements.
250.403(c).....................  Requested clarity for      The language proposed is   We revised the wording to
                                  paragraph (c) When you     very vague. It appears     clearly state when you
                                  move a drilling rig or     that a subsurface shut-    must shut in each well
                                  related equipment on a     in is only required to     below the surface and at
                                  platform. You must shut    move a rig while located   the wellhead. The final
                                  in each well below the     on a platform (i.e. from   wording is contained in
                                  surface and at the         well to well) and does     Sec.   250.406.
                                  wellhead, unless           not address rigging-up
                                  otherwise approved by      and rigging-down. Also
                                  the District Supervisor.   applicability to MODUs
                                                             is unclear (movement of
                                                             cantilever jack-ups and
                                                             floaters).
250.410(b)(3)..................  Form MMS-123S may require  We assume that Form MMS-   As previously discussed,
                                  modifications to include   123S will be modified to   MMS revised this form
                                  additional information     contain new information    and the other subpart D
                                  requirements. OOC          requirements. Therefore,   drilling and well forms
                                  requests that it be        we believe it would be     through a separate
                                  allowed to review and      beneficial to both         process. We provided an
                                  provide comments to the    industry and the MMS to    opportunity to comment
                                  MMS, if the form is        allow OOC to review the    on the revised forms and
                                  modified.                  new form.                  note that OOC did
                                                                                        comment.
250.413(h).....................  (h) delete...............  We recommend that Line     The revised paragraph (h)
                                                             (h) be deleted. It is      now says that your well
                                                             not clear how is this      drilling design criteria
                                                             additional summary is to   must include a summary
                                                             be submitted. (i.e. Is     report of the shallow
                                                             it to be included in       hazards site survey if
                                                             Form MMS 123S or is it a   it was not previously
                                                             narrative summary to       submitted.
                                                             part of the ADP, or is
                                                             it a separate
                                                             submittal?) The language
                                                             as proposed is unclear,
                                                             and OOC is not sure of
                                                             the intent, or the
                                                             purpose of this
                                                             additional reporting
                                                             requirement.
                                                             Additionally, the
                                                             summary report of the
                                                             shallow hazards site
                                                             survey will have been
                                                             previously submitted
                                                             with the EP/DOCD under
                                                             which the well will be
                                                             drilled.

[[Page 8412]]

 
250.414 (a), (b), (d), (e), (f)  Clarity is requested for   Currently the majority     With the exception of
 and (g).                         lines (a), (b), (d),       this of data is captured   providing the estimated
                                  (e), (f) and (g)--What     in the APD Information     depths to faults, these
                                  items must my drilling     Spreadsheet. However,      requirements were
                                  prognosis include? (a)     will the proposed form     contained in Sec.
                                  Projected plans for        MMS-123S include other     250.415(f)(5) of the
                                  coring at specified        required data, such as     current regulations. You
                                  depths; (b) Projected      estimated depths to the    may use form MMS-123S to
                                  plans for logging; (d)     top of significant         provide as much of this
                                  Estimated depths to the    marker formations, major   information as
                                  top of significant         faults, etc? OOC assumes   appropriate. Information
                                  marker formations; (e)     that the intent of the     you do not include on
                                  Estimated depths to        requirement is to          that form must be
                                  significant porous and     identify faults that can   included with the
                                  permeable zones            potentially lead to        drilling prognosis. As
                                  containing fresh water,    problems while drilling.   for estimating the
                                  oil, gas, or abnormally    Therefore, it is           depths to faults, we
                                  pressured formation        recommended that the       made the suggested
                                  fluids; (f) Estimated      language be modified to    change to require only
                                  depths to major faults;    include major faults       the estimated depths to
                                  and (g) Estimated depths   only.                      major faults.
                                  of permafrost, if
                                  applicable.
250.415(a).....................  Hole sizes and casing      The requirement for        We made this suggested
                                  sizes, including:          including the tension      change. We will continue
                                  weights; grades;           value has been deleted     to require the tension
                                  [tension] collapse, and    from the proposed          casing design safety
                                  burst values; types of     language. This             factor which is covered
                                  connection; and setting    information has not been   in paragraph (b).
                                  depths (measured and       required in the past.
                                  TVD).                      The need to now require
                                                             this information is
                                                             unclear. If this
                                                             requirement remains,
                                                             will the ADP Information
                                                             Spreadsheet/form MMS-
                                                             123S, be revised to
                                                             capture these values?
250.417(a).....................  (a) If sufficient          Clarity. The proposed      We added the phrase
                                  environmental              language is too broad      ``during operations'' to
                                  information and data are   and does not present       the requirement as
                                  not available, the         under which conditions     suggested. We did not
                                  District Supervisor may    the additional data        add the second sentence
                                  require you to collect     would be required.         because it is
                                  and report this                                       unnecessary. The context
                                  information during the                                of the section sets the
                                  period of operation. The                              limits for the type of
                                  information to be                                     information to be
                                  collected and reported                                collected.
                                  will be related to the
                                  structural integrity of
                                  the drilling unit and
                                  the safe conduct of
                                  operations.
250.417(b).....................  (b) The District           Clarity. The proposed      The sentence was revised
                                  Supervisor may require     language is too broad      as follows: The District
                                  you to conduct             and does not present       Supervisor may require
                                  additional surveys and     under which conditions     you to conduct
                                  soil borings before        the additional data        additional surveys and
                                  approving the APD, if      would be required.         soil borings before
                                  the District Supervisor                               approving the APD if
                                  cannot make a                                         additional information
                                  determination that the                                is needed to make a
                                  proposed drilling unit                                determination that the
                                  can be supported at the                               conditions are capable
                                  specific site.                                        of supporting the
                                                                                        drilling unit.
250.420(b)(1)..................  (b) Casing Requirements.   OOC recommends that the    We did not make the
                                  (1) You must design        phrase ``and               suggested change. This
                                  casing (including          combinations thereof''     is not a new requirement
                                  liners) to withstand the   be deleted because this    (currently in Sec.
                                  anticipated stresses       statement is vague as to   250.404(a)(3)). You must
                                  imposed by tensile,        what combinations must     design casing to
                                  compressive, and           be considered.             withstand all
                                  buckling loads; burst                                 combinations.
                                  and collapse pressures;
                                  thermal effects[; and
                                  combinations thereof].
250.420(b)(2)..................  (2) The casing design      OOC recommends that the    We did not make the
                                  must include safety        phrase ``and safe          suggested change. You
                                  measures that ensure       operations during the      must design your casing
                                  well control during        life of the well'' be      for the life of the
                                  drilling [and safe         deleted because it is      well.
                                  operations during the      too broad.
                                  life of the well].
250.421(b).....................  (b) Use enough cement to   Cement in the annular      We did not make this
                                  fill the annular space     area between the           suggested change.
                                  back to the mud line.      conductor and the drive/   Washing out or
                                  Verify annular fill by     structural pipe can        displacing cement is
                                  observing cement           cause difficulty in        covered by Sec.
                                  returns. If you cannot     cutting pipe and           250.418(g). That
                                  observe cement returns,    clearing the location      paragraph now says that
                                  use additional cement to   below the mud line.        washing out cement must
                                  ensure fill back to the                               be addressed in the APD.
                                  mud line. Excess cement
                                  may be washed out from
                                  the annulus below the
                                  mud line to a sufficient
                                  depth as necessary to
                                  facilitate well
                                  abandonment operations.
                                  For drilling * * *.

[[Page 8413]]

 
250.421(f).....................  If you use a liner as      It is common practice to   We did not make the
                                  conductor or surface       achieve the liner-lap      suggested change of
                                  casing, you must set the   lengths discussed          adding ``unless
                                  top of the liner at        herein. However, there     otherwise approved by
                                  least 200 feet above the   are instances when this    the District
                                  previous casing/liner      is undesirable and, in     Supervisor.'' In fact,
                                  shoe. If you use a liner   those cases, a liner top   we have removed that
                                  as an intermediate or      packer is typically        phrase from many
                                  production casing, you     installed to ensure a      sections because it is
                                  must set the top of the    good seal. The             unnecessary. The
                                  liner at least 100 feet    recommended language       District Supervisor has
                                  above the previous         change will provide the    the flexibility to
                                  casing shoe, unless        District Supervisor the    approve many requests
                                  otherwise approved by      flexibility to approve a   without that phrase in
                                  the District Supervisor.   shorter liner-lap.         the regulations. To
                                                                                        emphasize this
                                                                                        flexibility, we have
                                                                                        added to the drilling
                                                                                        regulations two
                                                                                        sections: Sec.
                                                                                        250.408, ``May I use
                                                                                        alternative procedures
                                                                                        or equipment during
                                                                                        drilling operations?'',
                                                                                        and Sec.   250.409,
                                                                                        ``May I obtain
                                                                                        departures from these
                                                                                        drilling requirements?''
250.421(f).....................  * * * If you use a liner   Existing regulations       We have revised this
                                  as an intermediate or      include language that      paragraph to read ``If
                                  production casing, you     prohibits the use of a     you use a liner as an
                                  must set the top of the    production liner when      intermediate string
                                  liner at least 100 feet    landed in a surface        below a surface string
                                  above the previous         casing. Is this no         or production casing
                                  casing shoe.               longer the case?.          below an intermediate
                                                                                        string, you must set the
                                                                                        top of the liner at
                                                                                        least 100 feet above the
                                                                                        previous casing shoe.''
                                                                                        MMS does not allow
                                                                                        production liner to be
                                                                                        set inside the surface
                                                                                        casing, thereby to be
                                                                                        used for production
                                                                                        except in very limited
                                                                                        conditions. Each such
                                                                                        liner set departure must
                                                                                        be individually
                                                                                        reviewed.
250.422(b).....................  When may I resume          The term ``in advance''    We made the following
                                  drilling after             in the proposed text is    changes to this
                                  cementing? * * * (b) If    very vague. We recommend   requirement: We replaced
                                  you plan to nipple down    it be removed and the      the phrase ``in
                                  your diverter or BOP       actual information         advance'' with ``before
                                  stack during the 8- or     necessary to make the      nippling down'' because
                                  12-hour waiting time,      determination be stated.   we wanted to ensure that
                                  you must determine, [in    However, we do agree       no one made the
                                  advance] when it will be   that the performance-      determination after
                                  safe to conduct this       based language as          nippling down. We
                                  activity. Your             written in Sec.            revised the last
                                  determination must be      250.422(b) is              sentence of the
                                  based on a knowledge of    appropriate. That is,      requirement to include
                                  formations conditions      making the operator        most of the wording
                                  encountered, presence of   responsible for            suggested.
                                  potential drilling         assessing when it is
                                  hazards, actual well       safe to nipple down well
                                  conditions while           control equipment. As a
                                  drilling, cementing and    prudent operator, this
                                  post cementing as well     assessment is made based
                                  as past experience.        on a knowledge of
                                                             formations conditions
                                                             encountered, presence of
                                                             potential drilling
                                                             hazards, actual well
                                                             conditions while
                                                             drilling, cementing and
                                                             post cementing as well
                                                             as past experience.
250.423(b).....................  (b) Change casing setting  It is recommended that     We changed this paragraph
                                  depths more than 100       approval be obtained if    to allow an increase of
                                  feet TVD from the          the casing depth change    casing setting depth of
                                  approved APD.              is more than 100 feet      up to 100 feet total
                                                             TVD, not measured depth.   vertical depth before
                                                             Additionally, if the       requiring a submittal to
                                                             casing becomes stuck       the District Supervisor.
                                                             while running or other     In the case where the
                                                             hole conditions prevent    casing setting depth
                                                             the running of casing to   fell short of the
                                                             the projected setting      planned depth, you would
                                                             depth, the operator        have to contact the
                                                             should be allowed to       District Supervisor only
                                                             cement the casing          if the well conditions
                                                             without seeking            warranted revising your
                                                             approval, and notify the   casing design (see Sec.
                                                             District Supervisor         250.423(a)).
                                                             subsequently.
250.423(h).....................  Submit geologic data and   The 500-foot limit is too  We did not make the
                                  information to the         prescriptive. This         suggested change. The
                                  District Supervisor that   waiver should be based     500-foot distance was
                                  demonstrates the absence   on the geologic data       selected by MMS
                                  of shallow hydrocarbons    from an applicable         geologists and drilling
                                  or hazards. This           analogous well.            engineers as a
                                  information must include                              reasonable distance. MMS
                                  logging, [and] drilling                               can best serve the
                                  fluid-monitoring and                                  industry by keeping the
                                  other available geologic                              500-foot distance in the
                                  data from wells                                       regulations (see Sec.
                                  previously drilled                                    250.428(g)).
                                  [within 500 feet] in the
                                  immediate vicinity of
                                  the proposed well path
                                  down to the next casing
                                  point.

[[Page 8414]]

 
250.424(a).....................  (a) You must pressure      There is more than one     We chose not to list the
                                  test each string of        currently approved         alternative methods for
                                  casing to 70 percent of    method for calculating     calculating casing test
                                  its minimum internal       casing test pressure. We   pressure. You should
                                  yield or as otherwise      recommend that the         address alternative test
                                  approved by the District   alternative test methods   pressures or methods in
                                  Supervisor. This testing   be included in the new     your APD (see Sec.
                                  requirement does not       requirements, or allow     250.423).
                                  apply to drive or          the District Supervisor
                                  structural casing. When    the discretion to
                                  a diverter is installed    approve alternative
                                  on conductor casing, you   methods.
                                  must test the casing to
                                  a minimum of 200 psi.
                                  [The District Supervisor
                                  may approve or require
                                  other casing test
                                  pressures.]
250.431(a).....................  (a) Use diverter spool     API line pipe is normally  We made the suggested
                                  outlets and diverter       used for diverter lines.   changes.
                                  lines that have [an        Line pipe is different
                                  internal diameter] a       than casing. The nominal
                                  nominal diameter of at     size of line pipe
                                  least 10 inches for        normally refers to the
                                  surface wellhead           OD (for larger sizes).
                                  configurations and at
                                  least 12 inches for
                                  floating drilling
                                  operations.
250.434........................  (f) After drilling is      To require the lessee to   We deleted paragraph (f)
                                  completed, [retain all     maintain detailed          and moved the
                                  the records listed in      drilling records at the    recordkeeping
                                  this section for 2 years   facility or at the         requirements to Sec.
                                  at the facility, at the    nearest field location     Sec.   250.466 and
                                  lessee's field office      after drilling is          250.467. Section 250.466
                                  nearest to the facility,   completed is               requires you to keep
                                  or at another location     unreasonable, and places   drilling records onsite
                                  conveniently available     an unnecessary             during drilling
                                  to the District            recordkeeping burden on    operations. After
                                  Supervisor.] the lessee    the operator. We do        completion of drilling
                                  must retain all the        maintain these records;    activities, you may keep
                                  records listed in this     however, they are          all records at a
                                  section for 2 years and    typically maintained in    location of your choice.
                                  make them available at     a central record center.   A table in Sec.
                                  the District               The need to maintain       250.467 gives the time
                                  Supervisor's request.      test results in the        periods for keeping all
                                                             field after the drill      records.
                                                             operations are completed
                                                             is unclear. Should the
                                                             need to review these
                                                             records arise, they can
                                                             be supplied at that time.
250.440........................  You must design, install,  Include test in the        We made the suggested
                                  maintain, test and use     proposed text to be        change.
                                  the BOP system and         complete and consistent
                                  system components to       with the existing
                                  ensure well control * *    requirements.
                                  *.
250.441(b).....................  (b) Delete...............  We strongly recommend      MMS did not make the
                                                             that this requirement be   suggested change. See
                                                             eliminated. We have        response to comments in
                                                             reviewed the description   the previous part of the
                                                             of the incidents used by   preamble.
                                                             the MMS to justify the    As for the $150,000 cost
                                                             proposed requirement to    per stack cited by OOC,
                                                             install blind-shear rams   we have used a cost of
                                                             in all BOP stacks and      $175,000 in our
                                                             disagree with the          evaluation of impacts.
                                                             conclusion that they
                                                             support the need to
                                                             require the installation
                                                             of blind-shear rams.
                                                             Furthermore, a 13\5/8\
                                                             inch blind-shear rams
                                                             would cost the drilling
                                                             contractor an estimated
                                                             $82,000 plus
                                                             transportation and
                                                             installation costs. The
                                                             total estimated cost
                                                             imposed by this
                                                             requirement would be
                                                             $150,000 per stack.
250.442(b).....................  (b) You must install a     Many BOP stacks on         Our changes to this
                                  subsea accumulator         floating drilling rigs     paragraph follow the
                                  closing unit, or           currently in operation     suggested changes (see
                                  equivalent systems to      do not meet the proposed   Sec.   250.442(c)).
                                  provide fast closure of    requirement to install a
                                  the BOP components and     subsea accumulator. In
                                  to operate all critical    lieu of subsea
                                  functions in case of a     accumulators, the
                                  loss of the power fluid    inclusion of redundant
                                  connection to the          power/control lines
                                  surface. The [subsea]      provides the equivalent
                                  accumulator must meet or   protection necessary.
                                  exceed the provisions of   Therefore, we recommend
                                  Section 13.3,              the inclusion of the
                                  Accumulator Volumetric     statement ``or
                                  Capacity, in API RP 53,    equivalent system'' to
                                  Recommended Practice for   the proposed language.
                                  Blowout Prevention
                                  Equipment Systems for
                                  Drilling Wells. The
                                  District Supervisor may
                                  approve a suitable
                                  alternative method.

[[Page 8415]]

 
250.442(d).....................  (d) Before removing the    Drillships and semi        We did not make this
                                  marine drilling riser,     submersible drilling       suggested change. MMS
                                  you must displace the      rigs with automatic        realizes that during an
                                  riser with seawater,       station keeping (ASK)      emergency you will not
                                  except in the case of an   systems may experience     be able to displace the
                                  emergency riser            ASK failures at which      riser with seawater, but
                                  disconnect, You must* *    time the well must be      this specific case does
                                  *.                         isolated with the BOP      not need to be addressed
                                                             and the marine riser       in the regulations (see
                                                             disconnection              Sec.   250.442(e)).
                                                             immediately to prevent
                                                             damage to well,
                                                             equipment, and rig. It
                                                             is therefore impractical
                                                             to displace the marine
                                                             riser with seawater
                                                             prior to an emergency
                                                             riser disconnect.
250.447(b).....................  (b) Before 14 days have    More frequent testing      We did not make the
                                  elapsed since your last    without a specified        suggested change. MMS
                                  BOP pressure test, you     interval is too broad.     sees no reason to set a
                                  must begin to test your                               fixed BOP testing
                                  BOP system before                                     interval for when the
                                  midnight on the 14th day                              District Supervisor may
                                  following the conclusion                              require more frequent
                                  of the previous test.                                 testing. MMS may choose
                                  However, the District                                 a test interval between
                                  Supervisor may [require                               7 and 14 days depending
                                  more frequent testing]                                on conditions or
                                  require the test to be                                performance. BOP
                                  performed before                                      performance that
                                  midnight on the 7th day                               warrants testing at less
                                  following the conclusion                              than 7-day intervals
                                  of the previous test, if                              would likely lead to
                                  conditions or BOP                                     shutting in the drilling
                                  performance warrant; and                              unit until you fix the
                                                                                        problems.
250.448(b).....................  (b) High Pressure tests    OOC recognizes and         MMS will not publish a
                                  for ram type * * *         appreciates MMS efforts    list of acceptable
                                  Clarity requested.         to allow for BOP high-     methods to calculate
                                                             pressure tests             MASP in the regulations.
                                                             requirements to include    We don't believe that it
                                                             either testing to rated    is appropriate to limit
                                                             working pressure, or to    the number of acceptable
                                                             500 psi above the          methods nor do we
                                                             maximum allowable          believe that such a list
                                                             Surface Pressure (MASP)    would provide clarity.
                                                             for the applicable
                                                             section of the hole.
                                                             However, we recommend
                                                             that the proposed rule
                                                             include acceptable
                                                             methods for calculating
                                                             MASP, to provide clarity.
250.448(c).....................  (c) High pressure test     Currently approved         We changed the paragraph
                                  for annular-type BOPs.     procedures for testing     to read ``The high
                                  The high pressure test     annular preventers allow   pressure test must equal
                                  must equal 70 percent of   for testing to a           70% of the rated working
                                  the rated 70 percent of    pressure less than 70%     pressure of the
                                  the rated working          of the working pressure,   equipment or to a
                                  pressure of the            such as testing to the     pressure approved in
                                  equipment, or as           MASP.                      your APD.''
                                  otherwise approved by
                                  the District Supervisor.
250.450(c).....................  (c) Document the           The requirement to record  Section 250.442(c)
                                  sequential order of BOP    closing times should be    requires that ``the
                                  and auxiliary equipment    removed. This              accumulator system
                                  testing and the pressure   requirement is not a       equipment must meet or
                                  and duration of each       common practice.           exceed the provisions of
                                  test. [For subsea BOP      Furthermore, there is no   Section 13.3,
                                  systems, you must also     requirement for maximum    Accumulator Volumetric
                                  record the closing times   closing time of a BOP,     Capacity, in API RP
                                  for annular and ram        and it is unclear how      53.'' Section 13.3.5 in
                                  preventers.] You may       the measurement of         API RP 53 says ``For
                                  reference a BOP test       closing time would be      subsea installations,
                                  plan if it is available    determined (is it from     the BOP control system
                                  at the facility.           the time the button is     should be capable of
                                                             pushed until the fluid     closing each ram BOP in
                                                             flow stop, or the time     45 seconds or less.
                                                             it takes the ram to        Closing should not
                                                             fully stroke?). We do      exceed 60 seconds for
                                                             not see the value added    annular BOPs.'' As
                                                             by recording this time.    discussed in the
                                                             Either, a BOP stack        preamble of the proposed
                                                             functions properly or      rule, we incorporated
                                                             not.                       API RP 53 by reference
                                                                                        so that both industry
                                                                                        and MMS would have
                                                                                        guidelines for
                                                                                        determining the minimum
                                                                                        requirements and
                                                                                        performance standards
                                                                                        for subsea accumulators
                                                                                        and BOP systems. As for
                                                                                        the measurement of
                                                                                        closing times, the RP
                                                                                        states that ``the
                                                                                        measurement of closing
                                                                                        response time begins at
                                                                                        pushing the button or
                                                                                        turning the control
                                                                                        valve handle to operate
                                                                                        the function and ends
                                                                                        when the BOP or valve is
                                                                                        closed, effecting a
                                                                                        seal. A BOP is
                                                                                        considered closed when
                                                                                        the regulated operating
                                                                                        pressure has recovered
                                                                                        to its nominal
                                                                                        setting.''

[[Page 8416]]

 
250.450(g).....................  (g) After drilling is      To require the lessee to   We deleted paragraph (g)
                                  completed, [retain all     maintain detailed          and moved the record-
                                  the records listed in      drilling records at the    keeping requirements to
                                  this section for 2 years   facility or at the         Sec.  Sec.   250.466 and
                                  at the facility, at the    nearest field office       250.467. See previous
                                  lessee's field office      nearest field location     discussion on Sec.
                                  nearest to the facility,   after drilling             250.434.
                                  or at another location     operations are completed
                                  conveniently available     is unreasonable, and
                                  to the District            places an unnecessary
                                  Supervisor.] the lessee    recordkeeping burden on
                                  must retain all the        the operator. We do not
                                  records listed in this     maintain these records;
                                  section for 2 years and    however, they are
                                  make them available at     typically maintained in
                                  the District               a central record center.
                                  Supervisor's request.      The need to maintain
                                                             test results in the
                                                             field after the drill
                                                             operations are completed
                                                             is unclear. Should the
                                                             need to review these
                                                             records arise, they can
                                                             be supplied at that time.
250.457(a).....................  (a) You must have and      There are many times on a  We agree with the comment
                                  maintain drilling fluid-   rig when circulation       and moved the paragraph
                                  testing equipment on the   does not occur during a    to become Sec.
                                  drilling rig at all        tour, or longer, and       250.456(i). The new
                                  times. You must test the   testing twice per day      paragraph says: ``When
                                  drilling fluid, when       (once each tour) has no    circulating, you must
                                  circulating at least       added value. Therefore,    test the drilling fluid
                                  once each tour or more     we recommend that this     at least once each tour
                                  frequently if conditions   be a requirement during    or more frequently if
                                  warrant. You must          circulation only.          conditions warrant. You
                                  perform the tests          Furthermore, the           tests must conform to
                                  according to industry-     proposed text is too       industry-accepted
                                  accepted practices.        broad in regards to what   practices and include
                                  Tests must include         type and why might the     density, viscosity, and
                                  density, viscosity, and    District Supervisor        gel and gel strength;
                                  gel strength;              require additional test.   hydrogenion
                                  hydrogenion                The recommended language   concentration;
                                  concentration;             is consistent with the     filtration; and any
                                  filtration; and any        existing requirements.     other tests the District
                                  other tests the District                              Supervisor requires for
                                  Supervisor requires for                               monitoring drilling
                                  monitoring and                                        fluid quality,
                                  maintaining drilling                                  prevention of downhole
                                  fluid quality for safe                                equipment problems and
                                  operations, prevention                                for kick detection. You
                                  of downhole equipment                                 must record . . . .''
                                  problems and for the
                                  detection of kicks. You
                                  must record * * *.
250.460(a).....................  Clarity requested........  The proposed language is   We agree with the comment
                                                             confusing. The title of    that the two paragraphs
                                                             this section is ``What     don't fit under this
                                                             are the requirements for   title. We moved
                                                             well testing?'' However,   paragraph (a) to its own
                                                             paragraph (a) discusses    section (now Sec.
                                                             determining formation      250.407 ``What tests
                                                             characteristics using      must I conduct to
                                                             formation fluid samples    determine reservoir
                                                             and logging. It seems      characteristics?)''
                                                             appropriate to put this    under general
                                                             paragraph in a section     requirements. We then re-
                                                             titled ``what type         titled this section
                                                             samples, survey and        ``What are the
                                                             tests of the formation     requirements for
                                                             are required.'' Please     conducting a well
                                                             refer to 30 CFR            test?''
                                                             250.401(e) in the
                                                             existing regulations.
250.461(a).....................  (a) Survey requirements    Digitally recording        We made the suggested
                                  for a vertical well: (1)   inclination surveys        changes.
                                  You must conduct           while drilling a
                                  inclination surveys on     vertical well is not
                                  each vertical well and     necessary or practical.
                                  [digitally] record the     Inclination surveys are
                                  results. Survey            used as a process
                                  intervals may not exceed   control check to ensure
                                  1,000 feet during the      that the well remains
                                  normal course of           near vertical. The
                                  drilling. (2) You must     subsequent surveys,
                                  also conduct a             which include both
                                  directional survey that    inclination and azimuth,
                                  provides both              can be digitally
                                  inclination and azimuth,   recorded in electronic
                                  and digitally record the   format. The phrase
                                  results in electronic      ``electronic format''
                                  format:                    has been add to clarify
                                                             that the record should
                                                             be stored electronically
                                                             for submittal to MMS,
                                                             not record as
                                                             ``fingers'' on a paper
                                                             copy.
250.461(e).....................  (e) If you drill within    The adjacent leaseholder   We revised the paragraph
                                  500 feet of an adjacent    should request the         by adding the following
                                  lease, the Regional        survey.                    sentence: ``This could
                                  Supervisor may require                                occur when the adjoining
                                  you to furnish a copy of                              leaseholder requests a
                                  the well's directional                                copy of the survey for
                                  survey to the affected                                the protection of
                                  leaseholder, if the                                   correlative rights.''
                                  leaseholder has
                                  requested the survey.
250.462(d).....................  (d) MMS ordered drill. An  Clarifies who will be      We made the suggested
                                  MMS authorized             consulted prior to         change.
                                  representative. The MMS    conducting the drill.
                                  representative will
                                  consult with your onsite
                                  representative before
                                  requiring the drill.

[[Page 8417]]

 
250.465(a)(1)..................  Receive written or oral    With weekends and          We made the suggested
                                  approval from the          holidays, it is often      change.
                                  District Supervisor        difficult to meet the 72-
                                  before you begin the       hour limitation.
                                  intended operation. If
                                  you get an oral
                                  approval, you must
                                  submit form MMS-124
                                  [within 72 hours] no
                                  later than the end of
                                  the 3rd business day
                                  following the oral
                                  approval. In all cases,
                                  you must meet the
                                  additional requirements
                                  in paragraph (b) of this
                                  section.
250.466(g).....................  (g) All other information  Proposed language is very  We made the suggested
                                  required by the District   broad. The recommended     changes.
                                  Supervisor in order to     language clarifies under
                                  evaluate resource          what circumstances will
                                  evaluation, waste          additional information
                                  prevention, conservation   be requested.
                                  of natural resources,
                                  protection of
                                  correlative rights,
                                  safety or protection of
                                  the environment.
250.467........................  Delete section...........  As written, this section   We renumbered this
                                                             appears to be for          section to 250.469. The
                                                             informational purposes,    purpose of this section
                                                             rather than a              is to inform you what
                                                             requirement.               records the District
                                                             Furthermore, the           Supervisor may require
                                                             proposed language is       you to submit. The
                                                             vague. Line (a)            paragraphs identify the
                                                             discusses an NTL; Line     following: (a) well
                                                             (b) Specifies              records, (b)
                                                             requirements for GOMR,     paleontological reports
                                                             but is silent on           and states that the
                                                             requirements for other     Regional Supervisor may
                                                             regions. Line (c) as       issue a Notice to
                                                             written appears that       Lessees that prescribes
                                                             this is not mandatory,     the manner, timeframe,
                                                             but at the discretion of   and format for
                                                             the District Supervisor,   submitting this
                                                             and Line (d) eliminates    information, and (c)
                                                             the prescriptive           service company reports.
                                                             requirements for           We moved the
                                                             legible, exact copies of   requirements to submit
                                                             service company records.   form MMS--133, Well
                                                                                        Activity Report, and
                                                                                        daily drilling reports
                                                                                        to the mandatory Sec.
                                                                                        Sec.   250.468(b) and
                                                                                        (c).
250.515 (b) and 250.615 (b)....  Delete this requirement..  Please refer to rationale  MMS did not make the
                                                             previously discussed in    suggested change. See
                                                             Section 250.441 of this    our response to comments
                                                             document.                  for Sec.   250.441.
----------------------------------------------------------------------------------------------------------------

Procedural Matters

Regulatory Planning and Review (Executive Order 12866)

    The Office of Mangement and Budget (OMB) has designated this a 
significant rule for OMB review under Executive Order 12866.
    (1) The rule will not have an effect of $100 million or more on the 
economy. It will not adversely affect in a material way the economy, 
productivity, competition, jobs, the environment, public health or 
safety, or State, local, or tribal governments or communities. The 
major purpose of this rule is the restructuring of the rule and 
simplifying the regulatory language. The restructuring and plain 
language revisions will not result in any economic effects to small or 
large entities. Some of the technical revisions will have a minor 
economic effect on lessees and drilling contractors.
    Specifically, given the existing industry structure (i.e., the 
number and size of affected regulated entities remain constant), MMS 
estimates the cost to implement the rule at $1 million annually.
    In addition to the annual costs, the rule requires the installation 
of blind-shear rams in surface BOP stacks that will result in a one-
time cost of $14,175,000. This rule allows a 3-year period for the 
installation of the new rams. The most significant benefits of 
preventing or minimizing some blowouts will be the reduced risk of 
injury or fatality to personnel and of environmental damage. Property 
damages (including lost productivity) resulting from blowouts will also 
be reduced by this final rule. Property and financial damages from a 
blowout or near blowout can range from minimal damage to a facility and 
the loss of a day's activity to the total loss of the drilling rig and 
production facility.
    MMS believes that the installation of blind-shear rams in surface 
BOP stacks could prevent or minimize approximately one blowout every 2 
years. This estimate comes from the 5 incidents that MMS identified 
where a blind-shear ram had helped or could have helped prevent or 
minimize a blowout over the past 10-year period (1992 to present). 
Considering that a single blowout could cause multiple fatalities, 
injuries, and tens of millions of dollars in property damage and 
financial losses, MMS believes that the benefits of this requirement 
will more than offset the cost of this new requirement.
    (2) This rule will not create a serious inconsistency or otherwise 
interfere with an action taken or planned by another agency. The rule 
does not affect how lessees or operators interact with other agencies. 
Nor does this rule affect how MMS will interact with other agencies.
    (3) This rule does not alter the budgetary effects or entitlements, 
grants, user fees, or loan programs or the rights or obligations of 
their recipients. The rule only addresses the regulatory requirements 
for obtaining permission to drill on the OCS and the safety of drilling 
operations.
    (4) OMB has determined that this rule raises novel legal or policy 
issues. The rule has some new policy issues, such as requiring minimum 
BOP maintenance requirements. OMB has determined that these issues make 
this rule a significant rule as defined in Executive Order 12866.

[[Page 8418]]

Regulatory Flexibility (RF) Act

    The Department of the Interior (DOI) certifies that this rule will 
not have a significant economic effect on a substantial number of small 
entities under the RF Act (5 U.S.C. 601 et seq.). This rule applies to 
all lessees and drilling contractors that operate on the OCS. Small 
lessees and drilling contractors that operate under this final rule 
would fall under the Small Business Administration's (SBA) North 
American Industry Classification System codes 211111, Crude Petroleum 
and Natural Gas Extraction, and 213111 Drilling Oil and Gas Wells. 
Under these codes, SBA considers all companies with fewer than 500 
employees to be a small business. Given the variability in the industry 
due to changes in the relative prices of oil and natural gas, the 
numbers of small entities affected by the rule may change over time. 
Based on data from 1998, we estimate that of the 130 lessees that 
explore for and produce oil and gas on the OCS, approximately 90 are 
small businesses (70 percent). We also estimate that 10 drilling 
contractors operate on the OCS, and none of those drilling contractors 
are classified as a small business. The number of drilling contractors 
is based on current drilling activity on the OCS, and the size of each 
drilling contractor is based on research into company statistics.
    Drilling requirement costs will be borne by the OCS lessees who 
explore for and produce oil and are dependent on the number of wells 
drilled. We estimate that the total annual cost of the new drilling 
requirements in this rule to be approximately $670,000, as shown in the 
following table. The table also shows the estimated cost per well for 
the approximately 700 wells drilled annually on the OCS using a surface 
BOP stack.

           Estimated Costs of Additional Drilling Requirements
------------------------------------------------------------------------
                                                              Total cost
                                                               for 700
                      Cost                         Cost per     wells
                                                     well      drilled
                                                               annually
------------------------------------------------------------------------
One hour per well additional evaluation time on        $100      $70,000
 cementing operations @ $100....................
One hour per well additional drilling rig rental        850     $595,000
 @ $850.........................................
Annual reporting and paperwork burden--140 hours         10       $7,000
 @ $50..........................................
                                                 ------------
    Total.......................................        960    $672,000
------------------------------------------------------------------------
* The annual reporting and paperwork burden for the entire subpart D,
  ``Oil and Gas Drilling Operations'' is 111,209 hours as indicated in
  the Paperwork Reduction Act of 1995 section of this preamble. However,
  the new burden added when the this rule was proposed is only 140 hours
  (Sec.   250.403-100 hours; Sec.   250.460(b)-30 hours; and Sec.
  250.461(e)--10 hours).

    As indicated in the table, the estimated cost per well is about 
$1,000. Based on drilling data from 1999, we estimate that the 90 small 
businesses that explore for and produce oil and gas on the OCS drill 
about 300 of the 700 wells drilled annually on the OCS using a surface 
BOP stack. Thus, with the small businesses drilling an average of 3\1/
3\ wells per year, the annual economic effect for each small business 
is about $3,300, or about $300,000 in total. The estimated additional 
cost of $1,000 per well is quite small (about .02 percent) when 
compared to the $5 million average cost of drilling a well. Based on 
this very low percentage of well cost, we believe that these revisions 
to the regulations will not have a significant economic effect on any 
small lessee.
    The estimated economic effect of the requirement to use blind-shear 
rams on surface BOP stacks is the cost to purchase the rams. This 
requirement imposes no reporting or recordkeeping burden. This 
requirement primarily will affect drilling contractors operating jackup 
and platform rigs on the OCS who will be required to purchase the rams. 
Using information from 2003, the cost for a set of 10,000 pounds per-
square-inch rams and associated equipment is about $105,000. Some sets 
of rams for lower-rated BOP stacks will cost less, while a few sets of 
rams will cost more for higher-rated BOP stacks, but the average cost 
will remain at about $105,000.
    In the proposed rule we estimated that drilling contractors would 
need to purchase a total of 80 blind-shear rams to meet the proposed 
requirements. We have revised that estimate to 135 sets of rams for 
reasons as discussed in our response to comments. At an average cost of 
about $105,000, the economic impact will be $14,175,000. The largest 
drilling contractor may need to purchase up to 40 sets of blind-shear 
rams, while one drilling contractor will not have to purchase any 
blind-shear rams because it has already installed blind-shear rams in 
all of its surface BOP stacks. When asked why, a company executive 
responded that it was a prudent safety measure. A large contractor may 
get a minor reduction in the cost with a bulk purchase, but this 
reduction should not significantly affect the competition between large 
and small contractors because the unit costs will not vary much. 
Purchase of the rams to meet the proposed requirements will be an 
initial one-time cost. A blind-shear ram should last for 20 years if 
properly maintained.
    The blind-shear ram requirement should not hinder the ability of 
lessees or contractors, including small businesses, to conduct business 
on the OCS. The final rule provides for a 3-year period after the 
effective date for drilling contractors to plan and purchase the rams 
and associated equipment. This will allow contractors sufficient time 
to obtain the equipment.
    The following table summarizes the estimated economic effects 
associated with this final rule.

----------------------------------------------------------------------------------------------------------------
                                                                                                   Cost to small
                 Requirement                               Frequency                Total cost      businesses
----------------------------------------------------------------------------------------------------------------
New drilling rules...........................  Annual...........................        $672,000        $300,000
Use of blind-shear rams......................  One-time.........................      14,175,000               0
                                                                                 -----------------
    Total....................................  .................................      14,847,000         300,000
----------------------------------------------------------------------------------------------------------------


[[Page 8419]]

    We do not believe that this rule will have a significant impact on 
the lessees and drilling contractors who explore for and produce oil 
and gas on the OCS, including those that are classified as small 
businesses.
    Your comments are important. The Small Business and Agriculture 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small business about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the actions of MMS, call 1-888-REG-
FAIR (1-888-734-3247). You may comment to the Small Business 
Administration without fear of retaliation. Disciplinary action for 
retaliation by an MMS employee may include suspension or termination 
from employment with the Department of the Interior.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This rule is not a major rule under (5 U.S.C. 804(2)) the SBREFA. 
The rule:
    (1) Does not have an annual effect on the economy of $100 million 
or more. As described above, we estimate that the annual cost of the 
rule to be approximately $672,000. The cost for the blind-shear rams 
will be $14,175,000, which will be spread over a 3-year period. This 
cost will not cause an annual effect on the economy of $100 million.
    (2) Will not cause a major increase in costs or prices for 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions. The minor increase in drilling costs 
will not change the way the oil and gas industry conducts business, nor 
will it affect regional oil and gas prices; therefore, it will not 
cause major cost increases for consumers, the oil and gas industry, or 
any Government agencies.
    (3) Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or ability of United 
States-based enterprises to compete with foreign-based enterprises. All 
lessees and drilling contractors, regardless of nationality, will have 
to comply with the requirements of this rule. So the rule will not 
affect competition, employment, investment, productivity, innovation, 
or the ability of United States-based enterprises to compete with 
foreign-based enterprises.

Paperwork Reduction Act (PRA) of 1995

    We examined the proposed rule and these final regulations under 
section 3507(d) of the PRA. The proposed rulemaking added only a few 
new information collection requirements, which we submitted to OMB for 
approval as part of the proposed rulemaking process. There have been 
some changes to the numbering of sections requiring the collection of 
information in the final regulations, as well as some clarifications. 
However, the final regulations do not impose any additional information 
collection paperwork burden.
    MMS regulations in 30 CFR 250, subpart A, at Sec. Sec.  250.140, 
250.141, and 250.142 allow respondents to request the use of 
``alternative procedures or equipment'' and ``departures'' to operating 
requirements. However, our information collection submission to OMB 
(1010-0114) indicated that the burden for these requests is covered 
under the applicable operating requirement. To account for these non-
specific possibilities, as MMS renews the various collections covering 
subparts of the part 250 regulations and the other 30 CFR parts, as a 
standard procedure we are now including these requests as a ``line 
item'' in the regulation burden charts. Based on comments we received 
on the proposed subpart D rulemaking, Sec. Sec.  250.408 and 250.409 of 
these final regulations specifically address these issues and a line 
item has been included in the burden chart for this collection. It 
should be reiterated that these requests are not new information 
collection requirements. However, this inclusion will ensure that the 
burden is not overlooked for some operating requirements and will 
provide for any oversight.
    Because of the adjustments discussed in the preceding paragraphs 
and section numbering changes, before publication, we again submitted 
the final subpart D information collection to OMB and OMB approved them 
under OMB control number 1010-0141, with a current expiration date of 
January 28, 2003. An agency may not conduct or sponsor, and you are not 
required to respond to, a collection of information unless it displays 
a currently valid OMB control number.
    The title of the collection of information for this final rule is 
``30 CFR 250, Subpart D--Oil and Gas Drilling Operations.'' Respondents 
include approximately 130 Federal OCS oil and gas or sulphur lessees. 
The frequency of response varies, depending upon the requirement. 
Responses are mandatory. MMS will protect proprietary information 
according to the Freedom of Information Act and 30 CFR 250.196, ``Data 
and information to be made available to the public.''
    The final regulations convert into plain language and restructure 
the requirements for oil and gas drilling operations. The approved 
information collection for this final rule will supersede the 
collection for current subpart D regulations (OMB control number 1010-
0053), which we will cancel when the new subpart D regulations take 
effect.
    We estimate the total annual paperwork ``hour'' burden for the 
final rule to be 111,209 hours. Following is a breakdown of the hour 
burden estimate.

[[Page 8420]]



--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                 Annual
     Citation 30 CFR 250 Subpart D            Reporting and recordkeeping requirement         Hour             Average number per year           burden
                                                                                             burden                                               hours
--------------------------------------------------------------------------------------------------------------------------------------------------------
402(b)................................  Request approval to use blind or blind-shear ram         .25  6 requests..............................         2
                                         or pipe rams and inside BOP.
403...................................  Notify MMS of drilling rig movement on or off            .1   20 notices..............................         2
                                         drilling location.
                                       --------------------------------------------------------------------------------------------------------
                                         In Gulf of Mexico OCS Region, rig movements reported on form MMS-144--burden covered under 1010-0150.
                                       --------------------------------------------------------------------------------------------------------
408, 409..............................  Apply for use alternative procedures and/or             1     20% of 1,200 drilling ops. = 240........       240
                                         departures not requested in MMS forms (including
                                         discussions with MMS and approvals.
                                       --------------------------------------------------------------------------------------------------------
408, 409; 410-418, plus various other      Apply for permit to drill and requests for various approvals required in subpart D (including Sec.          0
 references in subpart D.                 Sec.   250.423, 424, 442(c), 451(g), 456(f)) and obtained via forms MMS-123 (Application for Permit
                                          to Drill) and MMS-123S (Supplemental APD Information Sheet), and supporting information and notices
                                                                 to MMS--burden covered under 1010-0044 and 1010-0131.
                                       --------------------------------------------------------------------------------------------------------
410(a)(3), 417(b).....................    Reference to Exploration Plan, Development and Production Plan, Development Operations Coordination          0
                                                           Document (30 CFR 250, subpart B)--burden covered under 1010-0049.
                                       --------------------------------------------------------------------------------------------------------
417(a), (b)...........................  Collect and report additional information on case-      4     1 report................................         4
                                         by-case basis if sufficient information is not
                                         available.
                                       --------------------------------------------------------------------------------------------------------
417(c)................................     Submit 3rd party review of drilling unit according to 30 CFR 250, subpart I--burden covered under           0
                                                                                       1010-0058.
                                       --------------------------------------------------------------------------------------------------------
418(e)................................     Submit welding and burning plan according to 30 CFR 250, subpart A--burden covered under 1010-0114          0
                                       --------------------------------------------------------------------------------------------------------
421; 423; 428.........................  Submit casing and cementing program and revisions       2     20% of 1,200 drilling ops. = 240........       480
                                         or changes.
424...................................  Caliper, pressure test, or evaluate casing; submit      5     20% of 1,200 wells = 240................     1,200
                                         evaluation results; request approval before
                                         resuming operations or beginning repairs (every
                                         30 days during prolonged drilling).
456(c), (f)...........................  Perform various calculations; post information (on       .25  144 drilling rigs x 52 =7,488...........     1,872
                                         occasion, daily, weekly).
459(a)(3).............................  Request exception to procedure for protecting           2     5 requests..............................        10
                                         negative pressure area.
                                       --------------------------------------------------------------------------------------------------------
460; 465..............................    Submit revised plans, changes, well/drilling records, etc., on forms MMS-124 (Application for Permit         0
                                             to Modify) or MMS-125 (End of Operations Report)--burden covered under 1010-0045 and 1010-0046
                                       --------------------------------------------------------------------------------------------------------
460...................................  Submit plans for well testing and notify MMS            2     15 plans................................        30
                                         before test.
461(e)................................  Provide copy of well directional survey to              1     10 occasions............................        10
                                         affected leaseholder.
462(a)................................  Prepare and post well control drill plan for crew       3     26 plans................................        78
                                         members.
463(b)................................  Request field drilling rules be established,            2.5   6 requests..............................        15
                                         amended, or canceled.
468(a)................................  Submit well logs..................................      1.5   1,200 logs/surveys......................     1,800
                                        Submit directional and vertical-well surveys......       .5   1,200 reports...........................       600
                                        Submit velocity profiles and surveys..............       .25  55 reports..............................        14
                                        Submit core analyses..............................       .25  150 analyses............................        38
                                       --------------------------------------------------------------------------------------------------------
468(b); 465(b)(3).....................      In the GOM OCS Region, submit drilling activity reports on form MMS-133 (Well Activity Report)--           0
                                                                             burden covered under 1010-0132
                                       --------------------------------------------------------------------------------------------------------
468(c)................................  In the Pacific and Alaska OCS Regions during            1     14 wells x 365 days x 20% = 1,022.......     1,022
                                         drilling operations, submit daily drilling
                                         reports.
469...................................  As specified by region, submit well records,             .25  300 submissions.........................        75
                                         paleontological interpretations or reports,
                                         service company reports, and other reports or
                                         records of operations.
490(c)(4), (d)........................  Submit request for reclassification of H2S zone;        1.7   27 responses............................        46
                                         notify MMS if conditions change.
490(f); also referred to in 418(d)....  Submit contingency plans for operations in H2S         10     27 plans................................       270
                                         areas (16 drilling, 5 work-over, 6 production).
                                       --------------------------------------------------------------------------------------------------------
490(i)................................    Display warning signs--no burden as facilities would display warning signs and use other visual and          0
                                                                                    audible systems.
490(j)(12)............................    Propose alternatives to minimize or eliminate SO2 hazards--submitted with contingency plans--burden          0
                                                                               covered under 250.490(f).
490(j)(13)(vi)........................        Label breathing air bottles--no burden as supplier normally labels bottles; facilities would             0
                                                                                routinely label if not.
                                       --------------------------------------------------------------------------------------------------------
490(l)................................  Notify (phone) MMS of unplanned H2S releases             .2   49 facilities x 2 = 98..................        20
                                         (approx. 2/year).
490(o)(5).............................  Request approval to use drill pipe for well             2     3 requests..............................         6
                                         testing.
                                       --------------------------------------------------------------------------------------------------------

[[Page 8421]]

 
490(q)(1).............................        Seal and mark for the presence of H2S cores to be transported--no burden as facilities would             0
                                                                           routinely mark transported cores.
                                       --------------------------------------------------------------------------------------------------------
490(q)(9).............................  Request approval to use gas containing H2S for          2     3 requests..............................         6
                                         instrument gas.
490(q)(12)............................  Analyze produced water disposed of for H2S content      2.8   4 production platforms x 52 = 208.......       582
                                         and submit results to MMS on occasion (approx.
                                         weekly).
                                                                                           -----------
    Reporting Subtotal................  ..................................................  ........  12,590 Responses........................     8,422
                                                                                           -----------
404...................................  Perform operational check of crown block safety          .1   144 drilling rigs x 52 = 7,488..........       749
                                         device; record results (weekly).
426...................................  Perform pressure test on all casing strings and         2     144 drilling rigs x approx. 50 per rig =    14,400
                                         drilling liner lap; record results.                           7,200.
427(a)................................  Perform pressure-integrity tests and related hole-      4     425 tests...............................     1,700
                                         behavior observations; record results.
434; 467..............................  Perform diverter tests when installed and once          2     1,200 drilling ops. x 2 = 2,400.........     4,800
                                         every 7 days; actuate system at least once every
                                         24-hour period; record results (average 2 per
                                         drilling operation).
450; 467..............................  Perform BOP pressure tests, actuations and              6     144 drilling rigs x approx. 35 per rig =    30,240
                                         inspections when installed; at a minimum every 14             5,040.
                                         days; as stated for components; record results.
450, 467..............................  Function test annulars and rams; document results        .16  144 drilling rigs x approx. 20 per rig =       461
                                         every 7 days between BOP tests (biweekly). Note:              2,880.
                                         this test is part of BOP test when BOP test is
                                         conducted.
451(c)................................  Record reason for postponing BOP test (on                .1   144 drilling rigs x 2 = 288.............        29
                                         occasion--approx. 2/year).
456(b), (i); 458(b)...................  Record each drilling fluid circulation; test            1.25  144 drilling rigs x 52 = 7,488..........     9,360
                                         drilling fluid, record results; record daily
                                         inventory of drilling fluid/materials; test and
                                         recalibrate gas detectors; record results (on
                                         occasion, daily, weekly, quarterly).
462(c)................................  Perform well-control drills; record results (2          1     144 drilling rigs x 2 crews x 52 =          14,976
                                         crews weekly).                                                14,976.
466, 467..............................  Retain drilling records for 90 days after drilling      1.5   Annual records maintenance for 1,200         1,800
                                         is complete; retain casing/liner pressure,                    wells.
                                         diverter, and BOP for 2 years; retain well
                                         completion/well workover until well is
                                         permanently plugged/abandoned or lease assigned.
490(g)(2), (g)(5).....................  Conduct H2S training; post safety instructions;         2     49 facilities x 2 = 98..................       196
                                         document training on occasion and annual
                                         refresher (approx. 2/year).
490(h)(2).............................  Conduct weekly drills and safety meetings;              1     49 facilities x 52 = 2,548..............     2,548
                                         document attendance.
490(j)(8).............................  Test H2S detection and monitoring sensors during        2     26 drilling rigs x 365 days = 9,490.....    18,980
                                         drilling; record testing and calibrations on
                                         occasion, daily during drilling (approx. 12
                                         sensors per rig).
490(j)(8).............................  Test H2S detection and monitoring sensors every 14      3.5   28 production platforms x 26 = 728......     2,548
                                         days during production; record testing and
                                         calibrations (approx. 30 sensors/5 platforms +
                                         approx. 42 sensors/23 platforms).
                                       =====================================================
 
--------------------------------------------------------------------------------------------------------------------------------------------------------

Federalism (Executive Order 13132)

    According to Executive Order 13132, this rule does not have 
Federalism implications. This rule does not substantially and directly 
affect the relationship between the Federal and State Governments. The 
rule applies to lessees and drilling contractors that operate on the 
OCS. This rule does not impose costs on States or localities. Any costs 
will be the responsibility of the lessees and drilling contractors.

Takings Implication Assessment (Executive Order 12630)

    According to Executive Order 12630, the rule does not have 
significant Takings Implications. A Takings Implication Assessment is 
not required. The rule revises existing operation regulations. It does 
not prevent any lessee, operator, or drilling contractor from 
performing operations on the OCS, provided they follow the regulations. 
Thus, MMS did not need to prepare a Takings Implication Assessment 
under Executive Order 12630, Governmental Actions and Interference with 
Constitutionally Protected Property Rights.

Energy Supply, Distribution, or Use (Executive Order 13211)

    Although OMB has designated this a significant rule under Executive 
Order 12866, it does not have a significant effect on energy supply, 
distribution, or use. The rule essentially clarifies the current 
regulatory requirements for oil and gas drilling on the OCS. The rule 
also adds a new requirement (blind-shear rams in surface BOP stacks) 
that will result in a one-time cost to the industry of $14,175,000. 
However, the

[[Page 8422]]

increased safety aspects associated with the new requirement along with 
the potential for reduced property damages and financial losses will 
offset the $14,175,000 cost of the new rams. Accordingly the new 
requirement will not cause a reduction in crude oil supply or an 
increase in energy prices.

Civil Justice Reform (Executive Order 12988)

    According to Executive Order 12988, the Office of the Solicitor has 
determined that this rule does not unduly burden the judicial system 
and does meet the requirements of sections 3(a) and 3(b)(2) of the 
Order.

National Environmental Policy Act (NEPA)

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. An environmental 
assessment is not required.

Unfunded Mandates Reform Act (UMRA) of 1995 (Executive Order 12866)

    This rule does not impose an unfunded mandate on State, local, or 
tribal governments or the private sector of more than $100 million per 
year. The rule does not have any Federal mandates, nor does the rule 
have a significant or unique effect on State, local, or tribal 
governments or the private sector. A statement containing the 
information required by the UMRA (2 U.S.C. 1531 et seq.) is not 
required.

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Incorporation by reference, 
Investigations, Mineral royalties, Oil and gas development and 
production, Oil and gas exploration, Oil and gas reserves, Penalties, 
Pipelines, Public lands-mineral resources, Public lands-rights-of-way, 
Reporting and recordkeeping requirements, Sulphur development and 
production, Sulphur exploration, Surety bonds.

    Dated: October 24, 2002.
Rebecca W. Watson,
Assistant Secretary, Land and Minerals Management.

    For the reasons stated in the preamble, the Minerals Management 
Service (MMS) amends 30 CFR Part 250 as follows:

PART 250--OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 
CONTINENTAL SHELF

    1. The authority citation for part 250 continues to read as 
follows:

    Authority: 43 U.S.C. 1331 et seq.

    2. In Sec.  250.102, in the table in paragraph (b), paragraph (1) 
is revised to read as follows:

----------------------------------------------------------------------------------------------------------------
              For information about                                           Refer to
----------------------------------------------------------------------------------------------------------------
(1) Applications for permit to drill.............  Sec.   250.410
 
                                                   * * * * * *
----------------------------------------------------------------------------------------------------------------


    3. In Sec.  250.105, in the definition for Facility (3), the 
citation ``Sec.  250.417(b)'' is revised to read ``Sec.  250.490(b)''.

    4. In Sec.  250.198, in the table in paragraph (e), the following 
changes are made in alphanumeric order:
    A. Add an entry for API RP 53 as set forth below.
    B. Revise the entries for ANSI Z88.2-1992, API RP 500, API RP 505, 
and NACE Standard MR0175-99 as set forth below.


250.198  Documents incorporated by reference.

* * * * *
    (e) * * *

----------------------------------------------------------------------------------------------------------------
                Title of documents                                  Incorporated by reference at
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
ANSI Z88.2-1992, American National Standard for    Sec.   250.490(g)(4)(iv), (j)(13)(ii).
 Respiratory Protection.
 
                                                  * * * * * * *
API RP 53, Recommended Practices for Blowout       Sec.   250.442(c); Sec.   250.446(a).
 Prevention Equipment Systems for Drilling Wells,
 Third Edition, March 1997, API Stock No. G53003.
API RP 500, Recommended Practice for               Sec.   250.114(a); Sec.   250.459; Sec.   250.802(e)(4)(i);
 Classification of Locations for Electrical         Sec.   250.803(b)(9)(i); Sec.   250.1628(b)(3); (d)(4)(i);
 Installations at Petroleum Facilities,             Sec.   250.1629(b)(4)(i).
 Classified as Class I, Division 1 and Division
 2, Second Edition, November 1997, API Stock No.
 C50002.
API RP 505, Recommended Practice for               Sec.   250.114(a); Sec.   250.459; Sec.   250.802(e)(4)(i);
 Classification of Locations for Electrical         Sec.   250.803(b)(9)(i); Sec.   250.1628(b)(3); (d)(4)(i);
 Installations at Petroleum Facilities,             Sec.   250.1629(b)(4)(i).
 Classified as Class I, Zone 0, Zone 1, and Zone
 2, First Edition, November 1997, API Stock No.
 C50501.
 
                                                  * * * * * * *
NACE Standard MR0175-99, Sulfide Stress Cracking   Sec.   250.490(p)(2).
 Resistant Metallic Materials for Oilfield
 Equipment, Revised January 1999, NACE Item No.
 21302.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


    5. In Sec.  250.199, in the table in paragraph (e), the OMB control 
number ``1010-0053'' cited in the entry for item (4) is revised to read 
``1010-0141''.

    6. In Sec.  250.203, the following changes are made:
    A. In paragraphs (b)(5)(i) and (b)(5)(ii), the citation ``250.417'' 
is revised to read ``250.490''.
    B. In paragraph (p), the citation ``Sec.  250.414'' is revised to 
read ``Sec.  250.410 throughSec.  250.418''.

    7. In Sec.  250.204, the following changes are made:
    A. In paragraphs (b)(2)(i) and (b)(2)(ii), the citation ``Sec.  
250.417'' is revised to read Sec.  250.490''.

[[Page 8423]]

    B. In paragraph (t), the citation ``Sec.  250.414'' is revised to 
read ``Sec.  250.410 through Sec.  250.418''.

    8. In 30 CFR part 250, subpart D, Sec.  250.417 is redesignated as 
Sec.  250.490, Sec. Sec.  250.400 through 250.416 are revised, and 
Sec. Sec.  250.417 through 250.469 are added, and a new undesignated 
center heading is added preceding redesignated Sec. Sec.  250.490 to 
read as set forth below. For the convenience of the reader, the table 
of contents for subpart D is also set forth below:
Subpart D--Oil and Gas Drilling Operations

General Requirements

Sec.
250.400 Who is subject to the requirements of this subpart?
250.401 What must I do to keep wells under control?
250.402 When and how must I secure a well?
250.403 What drilling unit movements must I report?
250.404 What are the requirements for the crown block?
250.405 What are the safety requirements for diesel engines used on 
a drilling rig?
250.406 What additional safety measures must I take when I conduct 
drilling operations on a platform that has producing wells or has 
other hydrocarbon flow?
250.407 What tests must I conduct to determine reservoir 
characteristics?
250.408 May I use alternative procedures or equipment during 
drilling operations?
250.409 May I obtain departures from these drilling requirements?

Applying for a Permit To Drill

250.410 How do I obtain approval to drill a well?
250.411 What information must I submit with my application?
250.412 What requirements must the location plat meet?
250.413 What must my description of well drilling design criteria 
address?
250.414 What must my drilling prognosis include?
250.415 What must my casing and cementing programs include?
250.416 What must I include in the diverter and BOP descriptions?
250.417 What must I provide if I plan to use a mobile offshore 
drilling unit (MODU)?
250.418 What additional information must I submit with my APD?

Casing and Cementing Requirements

250.420 What well casing and cementing requirements must I meet?
250.421 What are the casing and cementing requirements by type of 
casing string?
250.422 When may I resume drilling after cementing?
250.423 What are the requirements for pressure testing casing?
250.424 What are the requirements for prolonged drilling operations?
250.425 What are the requirements for pressure testing liners?
250.426 What are the recordkeeping requirements for casing and liner 
pressure tests?
250.427 What are the requirements for pressure integrity tests?
250.428 What must I do in certain cementing and casing situations?

Diverter System Requirements

250.430 When must I install a diverter system?
250.431 What are the diverter design and installation requirements?
250.432 How do I obtain a departure to diverter design and 
installation requirements?
250.433 What are the diverter actuation and testing requirements?
250.434 What are the recordkeeping requirements for diverter 
actuations and tests?

Blowout Preventer (BOP) System Requirements

250.440 What are the general requirements for BOP systems and system 
components?
250.441 What are the requirements for a surface BOP stack?
250.442 What are the requirements for a subsea BOP stack?
250.443 What associated systems and related equipment must all BOP 
systems include?
250.444 What are the choke manifold requirements?
250.445 What are the requirements for kelly valves, inside BOPs, and 
drill-string safety valves?
250.446 What are the BOP maintenance and inspection requirements?
250.447 When must I pressure test the BOP system?
250.448 What are the BOP pressure tests requirements?
250.449 What additional BOP testing requirements must I meet?
250.450 What are the recordkeeping requirements for BOP tests?
250.451 What must I do in certain situations involving BOP equipment 
or systems?

Drilling Fluid Requirements

250.455 What are the general requirements for a drilling fluid 
program?
250.456 What safe practices must the drilling fluid program follow?
250.457 What equipment is required to monitor drilling fluids?
250.458 What quantities of drilling fluids are required?
250.459 What are the safety requirements for drilling fluid-handling 
areas?

Other Drilling Requirements

250.460 What are the requirements for conducting a well test?
250.461 What are the requirements for directional and inclination 
surveys?
250.462 What are the requirements for well-control drills?
250.463 Who establishes field drilling rules?

Applying for a Permit To Modify and Well Records

250.465 When must I submit an Application for Permit to Modify (AMP) 
or an End of Operations Report to MMS?
250.466 What records must I keep?
250.467 How long must I keep records?
250.468 What well records am I required to submit?
250.469 What other well records could I be required to submit?

Hydrogen Sulfide

250.490 Hydrogen sulfide.

Subpart D--Oil and Gas Drilling Operations

General Requirements


Sec.  250.400  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operating rights 
owners, operators, and their contractors and subcontractors.


Sec.  250.401  What must I do to keep wells under control?

    You must take necessary precautions to keep wells under control at 
all times. You must:
    (a) Use the best available and safest drilling technology to 
monitor and evaluate well conditions and to minimize the potential for 
the well to flow or kick;
    (b) Have a person onsite during drilling operations who represents 
your interests and can fulfill your responsibilities;
    (c) Ensure that the toolpusher, operator's representative, or a 
member of the drilling crew maintains continuous surveillance on the 
rig floor from the beginning of drilling operations until the well is 
completed or abandoned, unless you have secured the well with blowout 
preventers (BOPs), bridge plugs, cement plugs, or packers;
    (d) Use personnel trained according to the provisions of subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure 
the safety and protection of personnel, equipment, natural resources, 
and the environment.


Sec.  250.402  When and how must I secure a well?

    Whenever you interrupt drilling operations, you must install a 
downhole safety device, such as a cement plug, bridge plug, or packer. 
You must install the device at an appropriate depth within a properly 
cemented casing string or liner.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location; or

[[Page 8424]]

    (3) Repair to major drilling or well-control equipment.
    (b) For floating drilling operations, the District Supervisor may 
approve the use of blind or blind-shear rams or pipe rams and an inside 
BOP if you don't have time to install a downhole safety device or if 
special circumstances occur.


Sec.  250.403  What drilling unit movements must I report?

    (a) You must report the movement of all drilling units on and off 
drilling locations to the District Supervisor. This includes both MODU 
and platform rigs. You must inform the District Supervisor 24 hours 
before:
    (1) The arrival of an MODU on location;
    (2) The movement of a platform rig to a platform;
    (3) The movement of a platform rig to another slot;
    (4) The movement of an MODU to another slot; and
    (5) The departure of an MODU from the location.
    (b) You must provide the District Supervisor with the rig name, 
lease number, well number, and expected time of arrival or departure.
    (c) In the Gulf of Mexico OCS Region, you must report drilling unit 
movements on form MMS-144, Rig Movement Notification Report.


Sec.  250.404  What are the requirements for the crown block?

    You must have a crown block safety device that prevents the 
traveling block from striking the crown block. You must check the 
device for proper operation at least once per week and after each 
drill-line slipping operation and record the results of this 
operational check in the driller's report.


Sec.  250.405  What are the safety requirements for diesel engines used 
on a drilling rig?

    You must equip each diesel engine with an air take device to shut 
down the diesel engine in the event of a runaway.
    (a) For a diesel engine that is not continuously manned, you must 
equip the engine with an automatic shutdown device;
    (b) For a diesel engine that is continuously manned, you may equip 
the engine with either an automatic or remote manual air intake 
shutdown device;
    (c) You do not have to equip a diesel engine with an air intake 
device if it meets one of the following criteria:
    (1) Starts a larger engine;
    (2) Powers a firewater pump;
    (3) Powers an emergency generator;
    (4) Powers a BOP accumulator system;
    (5) Provides air supply to divers or confined entry personnel;
    (6) Powers temporary equipment on a nonproducing platform;
    (7) Powers an escape capsule; or
    (8) Powers a portable single-cylinder rig washer.


Sec.  250.406  What additional safety measures must I take when I 
conduct drilling operations on a platform that has producing wells or 
has other hydrocarbon flow?

    You must take the following safety measures when you conduct 
drilling operations on a platform with producing wells or that has 
other hydrocarbon flow:
    (a) You must install an emergency shutdown station near the 
driller's console;
    (b) You must shut in all producible wells located in the affected 
wellbay below the surface and at the wellhead when:
    (1) You move a drilling rig or related equipment on and off a 
platform. This includes rigging up and rigging down activities within 
500 feet of the affected platform;
    (2) You move or skid a drilling unit between wells on a platform;
    (3) A mobile offshore drilling unit (MODU) moves within 500 feet of 
a platform. You may resume production once the MODU is in place, 
secured, and ready to begin drilling operations.


Sec.  250.407  What tests must I conduct to determine reservoir 
characteristics?

    You must determine the presence, quantity, quality, and reservoir 
characteristics of oil, gas, sulphur, and water in the formations 
penetrated by logging, formation sampling, or well testing.


Sec.  250.408  May I use alternative procedures or equipment during 
drilling operations?

    You may use alternative procedures or equipment during drilling 
operations after receiving approval from the District Supervisor. You 
must identify and discuss your proposed alternative procedures or 
equipment in your Application for Permit to Drill (APD) (see Sec.  
250.414(h)). Procedures for obtaining approval are described in section 
250.141 of this part.


Sec.  250.409  May I obtain departures from these drilling 
requirements?

    The District Supervisor may approve departures from the drilling 
requirements specified in this subpart. You may apply for a departure 
from drilling requirements by writing to the District Supervisor. You 
should identify and discuss the departure you are requesting in your 
APD (see Sec.  250.414(h)).

Applying for a Permit To Drill


Sec.  250.410  How do I obtain approval to drill a well?

    You must obtain written approval from the District Supervisor 
before you begin drilling any well or before you sidetrack, bypass, or 
deepen a well. To obtain approval, you must:
    (a) Submit the information required by Sec.  250.411 through 
250.418;
    (b) Include the well in your approved Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD);
    (c) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 253; and
    (d) Submit the following forms to the District Supervisor:
    (1) An original and two complete copies of form MMS-123, 
Application for a Permit to Drill (APD), and form MMS-123S, 
Supplemental APD Information Sheet; and
    (2) A separate public information copy of forms MMS-123 and MMS-
123S that meets the requirements of Sec.  250.127.


Sec.  250.411  What information must I submit with my application?

    In addition to forms MMS-123 and MMS-123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
 Information that you must include with an
                    APD                     Where to find a  description
------------------------------------------------------------------------
(a) Plat that shows locations of the        Sec.   250.412
 proposed well.
(b) Design criteria used for the proposed   Sec.   250.413
 well.
(c) Drilling prognosis....................  Sec.   250.414
(d) Casing and cementing programs.........  Sec.   250.415
(e) Diverter and BOP systems descriptions.  Sec.   250.416
(f) Requirements for using an MODU........  Sec.   250.417

[[Page 8425]]

 
(g) Additional information................  Sec.   250.418
------------------------------------------------------------------------

Sec.  250.412  What requirements must the location plat meet?

    The location plat must:
    (a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
    (b) Show the surface and subsurface locations of the proposed well 
and all the wells in the vicinity;
    (c) Show the surface and subsurface locations of the proposed well 
in feet or meters from the block line;
    (d) Contain the longitude and latitude coordinates, and either 
Universal Transverse Mercator grid-system coordinates or state plane 
coordinates in the Lambert or Transverse Mercator Projection system for 
the surface and subsurface locations of the proposed well; and
    (e) State the units and geodetic datum (including whether the datum 
is North American Datum 27 or 83) for these coordinates. If the datum 
was converted, you must state the method used for this conversion, 
since the various methods may produce different values.


Sec.  250.413  What must my description of well drilling design 
criteria address?

    Your description of well drilling design criteria must address:
    (a) Pore pressures;
    (b) Formation fracture gradients, adjusted for water depth;
    (c) Potential lost circulation zones;
    (d) Drilling fluid weights;
    (e) Casing setting depths;
    (f) Maximum anticipated surface pressures. For this section, 
maximum anticipated surface pressures are the pressures that you 
reasonably expect to be exerted upon a casing string and its related 
wellhead equipment. In calculating maximum anticipated surface 
pressures, you must consider: drilling, completion, and producing 
conditions; drilling fluid densities to be used below various casing 
strings; fracture gradients of the exposed formations; casing setting 
depths; total well depth; formation fluid types; safety margins; and 
other pertinent conditions. You must include the calculations used to 
determine the pressures for the drilling and the completion phases, 
including the anticipated surface pressure used for designing the 
production string;
    (g) A single plot containing estimated pore pressures, formation 
fracture gradients, proposed drilling fluid weights, and casing setting 
depths in true vertical measurements;
    (h) A summary report of the shallow hazards site survey that 
describes the geological and manmade conditions if not previously 
submitted; and
    (i) Permafrost zones, if applicable.


Sec.  250.414  What must my drilling prognosis include?

    Your drilling prognosis must include a brief description of the 
procedures you will follow in drilling the well. This prognosis 
includes but is not limited to the following:
    (a) Projected plans for coring at specified depths;
    (b) Projected plans for logging;
    (c) Planned safe drilling margin between proposed drilling fluid 
weights and estimated pore pressures. This safe drilling margin may be 
shown on the plot required by Sec.  250.413(g);
    (d) Estimated depths to the top of significant marker formations;
    (e) Estimated depths to significant porous and permeable zones 
containing fresh water, oil, gas, or abnormally pressured formation 
fluids;
    (f) Estimated depths to major faults;
    (g) Estimated depths of permafrost, if applicable;
    (h) A list and description of all requests for using alternative 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternative procedures 
afford an equal or greater degree of protection, safety, or 
performance, or why you need the departures; and
    (i) Projected plans for well testing (refer to Sec.  250.460 for 
safety requirements).


Sec.  250.415  What must my casing and cementing programs include?

    Your casing and cementing programs must include:
    (a) Hole sizes and casing sizes, including: weights; grades; 
collapse, and burst values; types of connection; and setting depths 
(measured and true vertical depth (TVD));
    (b) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values;
    (c) Type and amount of cement (in cubic feet) planned for each 
casing string; and
    (d) In areas containing permafrost, setting depths for conductor 
and surface casing based on the anticipated depth of the permafrost. 
Your program must provide protection from thaw subsidence and 
freezeback effect, proper anchorage, and well control.


Sec.  250.416  What must I include in the diverter and BOP 
descriptions?

    You must include in the diverter and BOP descriptions:
    (a) A description of the diverter system and its operating 
procedures;
    (b) A schematic drawing of the diverter system (plan and elevation 
views) that shows: (1) the size of the annular BOP installed in the 
diverter housing;
    (2) spool outlet internal diameter(s);
    (3) diverter-line lengths and diameters; burst strengths and radius 
of curvature at each turn; and
    (4) valve type, size, working pressure rating, and location;
    (c) A description of the BOP system and system components, 
including pressure ratings of BOP equipment and proposed BOP test 
pressures;
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, location of 
choke and kill lines, and associated valves; and
    (e) Information that shows the blind-shear rams installed in the 
BOP stack (both surface and subsea stacks) are capable of shearing the 
drill pipe in the hole under maximum anticipated surface pressures.


Sec.  250.417  What must I provide if I plan to use a mobile offshore 
drilling unit (MODU)?

    If you plan to use a MODU, you must provide:
    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling location. This information must include the maximum 
environmental and operational conditions that the unit is designed to 
withstand, including the minimum air gap necessary for both hurricane 
and non-hurricane seasons. If sufficient environmental information and 
data are not available at the time you submit your APD, the District 
Supervisor may approve your APD but require you to collect and report 
this information during operations. Under this circumstance, the 
District Supervisor has the right to revoke the approval of the APD if 
information collected during operations show that the drilling unit is 
not capable of performing at the proposed location.

[[Page 8426]]

    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD, you may reference that 
information. The District Supervisor may require you to conduct 
additional surveys and soil borings before approving the APD if 
additional information is needed to make a determination that the 
conditions are capable of supporting the drilling unit.
    (c) Frontier areas. (1) If the design of the drilling unit you plan 
to use in a frontier area is unique or has not been proven for use in 
the proposed environment, the District Supervisor may require you to 
submit a third-party review of the unit's design. If required, you must 
obtain the third-party review according to Sec.  250.903. You may 
submit this information before submitting an APD.
    (2) If you plan to drill in a frontier area, you must have a 
contingency plan that addresses design and operating limitations of the 
drilling unit. Your plan must identify the actions necessary to 
maintain safety and prevent damage to the environment. Actions must 
include the suspension, curtailment, or modification of drilling or rig 
operations to remedy various operational or environmental situations 
(e.g. vessel motion, riser offset, anchor tensions, wind speed, wave 
height, currents, icing or ice-loading, settling, tilt or lateral 
movement, resupply capability).
    (d) U.S. Coast Guard (USCG) Documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the 
USCG. You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (e) Floating drilling unit. If you use a floating drilling unit, 
you must indicate that you have a contingency plan for moving off 
location in an emergency situation.
    (f) Inspection of unit. The drilling unit must be available for 
inspection by the District Supervisor before commencing operations.
    (g) Once the District Supervisor has approved a MODU for use, you 
do not need to re-submit the information required by this section for 
another APD to use the same MODU unless changes in equipment affect its 
rated capacity to operate in the District.


Sec.  250.418  What additional information must I submit with my APD?

    You must include the following with the APD:
    (a) Rated capacities of the drilling rig and major drilling 
equipment, if not already on file with the appropriate District office;
    (b) A drilling fluids program that includes the minimum quantities 
of drilling fluids and drilling fluid materials, including weight 
materials, to be kept at the site;
    (c) A proposed directional plot if the well is to be directionally 
drilled;
    (d) A Hydrogen Sulfide Contingency Plan (see Sec.  250.490), if 
applicable, and not previously submitted;
    (e) A welding plan (see Sec. Sec.  250.109 to 250.113) if not 
previously submitted;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A request for approval if you plan to wash out or displace some 
cement to facilitate casing removal upon well abandonment; and
    (h) Such other information as the District Supervisor may require.

Casing and Cementing Requirements


Sec.  250.420  What well casing and cementing requirements must I meet?

    You must case and cement all wells. Your casing and cementing 
programs must meet the requirements of this section and of Sec. Sec.  
250.421 through 250.428.
    (a) Casing and cementing program requirements. Your casing and 
cementing programs must:
    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination; and
    (5) Support unconsolidated sediments.
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the 
well.
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi before 
drilling out of the casing or before commencing completion operations.


Sec.  250.421  What are the casing and cementing requirements by type 
of casing string?

    The table in this section identifies specific design, setting, and 
cementing requirements for casing strings and liners. For the purposes 
of subpart D, the casing strings in order of normal installation are as 
follows: drive or structural, conductor, surface, intermediate, and 
production casings (including liners). The District Supervisor may 
approve or prescribe other casing and cementing requirements where 
appropriate.

----------------------------------------------------------------------------------------------------------------
                   Casing type                          Casing requirements           Cementing requirements
----------------------------------------------------------------------------------------------------------------
(a) Drive or Structural.........................  Set by driving, jetting, or     If you drilled a portion of
                                                   drilling to the minimum depth   this hole, you must use
                                                   as approved or prescribed by    enough cement to fill the
                                                   the District Supervisor.        annular space back to the
                                                                                   mudline.
(b) Conductor...................................  Design casing and select        Use enough cement to fill the
                                                   setting depths based on         calculated annular space back
                                                   relevant engineering and        to the mudline.
                                                   geologic factors. These        Verify annular fill by
                                                   factors include the presence    observing cement returns. If
                                                   or absence of hydrocarbons,     you cannot observe cement
                                                   potential hazards, and water    returns, use additional
                                                   depths.                         cement to ensure fill-back to
                                                  Set casing immediately before    the mudline.
                                                   drilling into formations       For drilling on an artificial
                                                   known to contain oil or gas.    island or when using a glory
                                                   If you encounter oil or gas     hole, you must discuss the
                                                   or unexpected formation         cement fill level with the
                                                   pressure before the planned     District Supervisor.
                                                   casing point, you must set
                                                   casing immediately.

[[Page 8427]]

 
(c) Surface.....................................  Design casing and select        Use enough cement to fill the
                                                   setting depths based on         calculated annular space to
                                                   relevant engineering and        at least 200 feet inside the
                                                   geologic factors. These         conductor casing.
                                                   factors include the presence   When geologic conditions such
                                                   or absence of hydrocarbons,     as near-surface fractures and
                                                   potential hazards, and water    faulting exist, you must use
                                                   depths.                         enough cement to fill the
                                                                                   calculated annular space to
                                                                                   the mudline.
(d) Intermediate................................  Design casing and select        Use enough cement to cover and
                                                   setting depth based on          isolate all hydrocarbon-
                                                   anticipated or encountered      bearing zones and isolate
                                                   geologic characteristics or     abnormal pressure intervals
                                                   wellbore conditions.            from normal pressure
                                                                                   intervals in the well.
                                                                                  As a minimum, you must cement
                                                                                   the annular space 500 feet
                                                                                   above the casing shoe and 500
                                                                                   feet above each zone to be
                                                                                   isolated.
(e) Production..................................  Design casing and select        Use enough cement to cover or
                                                   setting depth based on          isolate all hydrocarbon-
                                                   anticipated or encountered      bearing zones above the shoe.
                                                   geologic characteristics or    As a minimum, you must cement
                                                   wellbore conditions.            the annular space at least
                                                                                   500 feet above the casing
                                                                                   shoe and 500 feet above the
                                                                                   uppermost hydrocarbon-bearing
                                                                                   zone.
(f) Liners......................................  If you use a liner as           Same as cementing requirements
                                                   conductor or surface casing,    for specific casing types.
                                                   you must set the top of the     For example, a liner used as
                                                   liner at least 200 feet above   intermediate casing must be
                                                   the previous casing/liner       cemented according to the
                                                   shoe.                           cementing requirements for
                                                  If you use a liner as an         intermediate casing.
                                                   intermediate string below a
                                                   surface string or production
                                                   casing below an intermediate
                                                   string, you must set the top
                                                   of the liner at least 100
                                                   feet above the previous
                                                   casing shoe..
----------------------------------------------------------------------------------------------------------------

Sec.  250.422  When may I resume drilling after cementing?

    (a) After cementing surface, intermediate, or production casing (or 
liners), you may resume drilling after the cement has been held under 
pressure for 12 hours. For conductor casing, you may resume drilling 
after the cement has been held under pressure for 8 hours. One 
acceptable method of holding cement under pressure is to use float 
valves to hold the cement in place.
    (b) If you plan to nipple down your diverter or BOP stack during 
the 8- or 12-hour waiting time, you must determine, before nippling 
down, when it will be safe to do so. You must base your determination 
on a knowledge of formation conditions, cement composition, effects of 
nippling down, presence of potential drilling hazards, well conditions 
during drilling, cementing, and post cementing, as well as past 
experience.


Sec.  250.423  What are the requirements for pressure testing casing?

    The table in this section describes the minimum test pressures for 
each string of casing. You may not resume drilling or other down-hole 
operations until you obtain a satisfactory pressure test. If the 
pressure declines more than 10 percent in a 30-minute test or if there 
is another indication of a leak, you must re-cement, repair the casing, 
or run additional casing to provide a proper seal. The District 
Supervisor may approve or require other casing test pressures.

------------------------------------------------------------------------
            Casing type                     Minimum test pressure
------------------------------------------------------------------------
(a) Drive or Structural............  Not required
(b) Conductor......................  200 psi
(c) Surface, Intermediate, and       70 percent of its minimum internal
 Production.                          yield
------------------------------------------------------------------------

Sec.  250.424  What are the requirements for prolonged drilling 
operations?

    If wellbore operations continue for more than 30 days within a 
casing string run to the surface:
    (a) You must stop drilling operations as soon as practicable, and 
evaluate the effects of the prolonged operations on continued drilling 
operations and the life of the well. At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District 
Supervisor and obtain approval of those results before resuming 
operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Supervisor before you begin 
repairs.


Sec.  250.425  What are the requirements for pressure testing liners?

    (a) You must test each drilling liner (and liner-lap) to a pressure 
at least equal to the anticipated pressure to which the liner will be 
subjected during the formation pressure-integrity test below that liner 
shoe, or subsequent liner shoes if set. The District Supervisor may 
approve or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a 
minimum of 500 psi above the formation fracture pressure at the casing 
shoe into which the liner is lapped.
    (c) You may not resume drilling or other down-hole operations until 
you obtain a satisfactory pressure test. If the pressure declines more 
than 10 percent in a 30-minute test or if there is another indication 
of a leak, you must re-cement, repair the liner, or run additional 
casing/liner to provide a proper seal.

[[Page 8428]]

Sec.  250.426  What are the recordkeeping requirements for casing and 
liner pressure tests?

    You must record the time, date, and results of each pressure test 
in the driller's report maintained under standard industry practice. In 
addition, you must record each test on a pressure chart and have your 
onsite representative sign and date the test as being correct.


Sec.  250.427  What are the requirements for pressure integrity tests?

    You must conduct a pressure integrity test below the surface casing 
or liner and all intermediate casings or liners. The District 
Supervisor may require you to run a pressure-integrity test at the 
conductor casing shoe if warranted by local geologic conditions or the 
planned casing setting depth. You must conduct each pressure integrity 
test after drilling at least 10 feet but no more than 50 feet of new 
hole below the casing shoe. You must test to either the formation leak-
off pressure or to an equivalent drilling fluid weight if identified in 
an approved APD.
    (a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut 
drilling fluid, and well kicks to adjust the drilling fluid program and 
the setting depth of the next casing string. You must record all test 
results and hole-behavior observations made during the course of 
drilling related to formation integrity and pore pressure in the 
driller's report.
    (b) While drilling, you must maintain the safe drilling margin 
identified in the approved APD. When you cannot maintain this safe 
margin, you must suspend drilling operations and remedy the situation.


Sec.  250.428  What must I do in certain cementing and casing 
situations?

    The table in this section describes actions that lessees must take 
when certain situations occur during casing and cementing activities.

------------------------------------------------------------------------
 If you encounter the following
           situation:                       Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation     Submit a revised casing program to the
 pressures or conditions that      District Supervisor for approval.
 warrant revising your casing
 design.
(b) Need to increase casing       Submit those changes to the District
 setting depths more than 100      Supervisor for approval.
 feet true vertical depth (TVD)
 from the approved APD due to
 conditions encountered during
 drilling operations.
(c) Have indication of            (1) Pressure test the casing shoe; (2)
 inadequate cement job (such as    Run a temperature survey; (3) Run a
 lost returns, cement              cement bond log; or (4) Use a
 channeling, or failure of         combination of these techniques.
 equipment).
(d) Inadequate cement job.......  Re-cement or take other remedial
                                   actions as approved by the District
                                   Supervisor.
(e) Primary cement job that did   Isolate those intervals from normal
 not isolate abnormal pressure     pressures by squeeze cementing before
 intervals.                        you complete; suspend operations; or
                                   abandon the well, whichever occurs
                                   first.
(f) Decide to produce a well      Have at least two cemented casing
 that was not originally           strings (does not include liners) in
 contemplated for production.      the well. Note: All producing wells
                                   must have at least two cemented
                                   casing strings.
(g) Want to drill a well without  Submit geologic data and information
 setting conductor casing.         to the District Supervisor that
                                   demonstrates the absence of shallow
                                   hydrocarbons or hazards. This
                                   information must include logging and
                                   drilling fluid-monitoring from wells
                                   previously drilled within 500 feet of
                                   the proposed well path down to the
                                   next casing point.
(h) Need to use less than         Submit information to the District
 required cement for the surface   Supervisor that demonstrates the use
 casing during floating drilling   of less cement is necessary.
 operations to provide
 protection from burst and
 collapse pressures.
(i) Cement across a permafrost    Use cement that sets before it freezes
 zone.                             and has a low heat of hydration.
(j) Leave the annulus opposite a  Fill the annulus with a liquid that
 permafrost zone uncemented.       has a freezing point below the
                                   minimum permafrost temperature and
                                   minimizes opposite a corrosion.
------------------------------------------------------------------------

Diverter System Requirements


Sec.  250.430  When must I install a diverter system?

    You must install a diverter system before you drill a conductor or 
surface hole. The diverter system consists of a diverter sealing 
element, diverter lines, and control systems. You must design, install, 
use, maintain, and test the diverter system to ensure proper diversion 
of gases, water, drilling fluid, and other materials away from 
facilities and personnel.


Sec.  250.431  What are the diverter design and installation 
requirements?

    You must design and install your diverter system to:
    (a) Use diverter spool outlets and diverter lines that have a 
nominal diameter of at least 10 inches for surface wellhead 
configurations and at least 12 inches for floating drilling operations;
    (b) Use dual diverter lines arranged to provide for downwind 
diversion capability;
    (c) Use at least two diverter control stations. One station must be 
on the drilling floor. The other station must be in a readily 
accessible location away from the drilling floor;
    (d) Use only remote-controlled valves in the diverter lines. All 
valves in the diverter system must be full-opening. You may not install 
manual or butterfly valves in any part of the diverter system;
    (e) Minimize the number of turns (only one 90-degree turn allowed 
for each line for bottom-founded drilling units) in the diverter lines, 
maximize the radius of curvature of turns, and target all right angles 
and sharp turns;
    (f) Anchor and support the entire diverter system to prevent 
whipping and vibration; and
    (g) Protect all diverter-control instruments and lines from 
possible damage by thrown or falling objects.


Sec.  250.432  How do I obtain a departure to diverter design and 
installation requirements?

    The table below describes possible departures from the diverter 
requirements and the conditions required for each departure. To obtain 
one of these departures, you must have discussed the departure in your 
APD and received approval from the District Supervisor.

[[Page 8429]]



------------------------------------------------------------------------
   If you want a departure to:               Then you must...
------------------------------------------------------------------------
(a) Use flexible hose for         Use flexible hose that has integral
 diverter lines instead of rigid   end couplings.
 pipe.
(b) Use only one spool outlet     (1) Have branch lines that meet the
 for your diverter system.         minimum internal diameter
                                   requirements; and (2) Provide
                                   downwind diversion capability.
(c) Use a spool with an outlet    Use a spool that has dual outlets with
 with an internal diameter of      an internal diameter of at least 8
 less than 10 inches on a          inches.
 surface wellhead.
(d) Use a single diverter line    Maintain an appropriate vessel heading
 for floating drilling             to provide for downwind diversion.
 operations on a dynamically
 positioned drillship.
------------------------------------------------------------------------

Sec.  250.433  What are the diverter actuation and testing 
requirements?

    When you install the diverter system, you must actuate the diverter 
sealing element, diverter valves, and diverter-control systems and 
control stations. You must also flow-test the vent lines.
    (a) For drilling operations with a surface wellhead configuration, 
you must actuate the diverter system at least once every 24-hour period 
after the initial test. After you have nippled up on conductor casing, 
you must pressure-test the diverter-sealing element and diverter valves 
to a minimum of 200 psi. While the diverter is installed, you must 
conduct subsequent pressure tests within 7 days after the previous 
test.
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system within 7 days after the previous 
actuation.
    (c) You must alternate actuations and tests between control 
stations.


Sec.  250.434  What are the recordkeeping requirements for diverter 
actuations and tests?

    You must record the time, date, and results of all diverter 
actuations and tests in the driller's report. In addition, you must:
    (a) Record the diverter pressure test on a pressure chart;
    (b) Require your onsite representative to sign and date the 
pressure test chart;
    (c) Identify the control station used during the test or actuation;
    (d) Identify problems or irregularities observed during the testing 
or actuations and record actions taken to remedy the problems or 
irregularities; and
    (e) Retain all pressure charts and reports pertaining to the 
diverter tests and actuations at the facility for the duration of 
drilling the well.

Blowout Preventer (BOP) System Requirements


Sec.  250.440  What are the general requirements for BOP systems and 
system components?

    You must design, install, maintain, test, and use the BOP system 
and system components to ensure well control. The working-pressure 
rating of each BOP component must exceed maximum anticipated surface 
pressures. The BOP system includes the BOP stack and associated BOP 
systems and equipment.


Sec.  250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must include at least four remote-controlled, hydraulically operated 
BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, 
and one BOP equipped with blind or blind-shear rams.
    (b) No later than February 21, 2006, your surface BOP stack must 
include at least four remote-controlled, hydraulically operated BOPs 
consisting of an annular BOP, two BOPs equipped with pipe rams, and one 
BOP equipped with blind-shear rams. The blind-shear rams must be 
capable of shearing the drill pipe that is in the hole.
    (c) You must install an accumulator system that provides 1.5 times 
the volume of fluid capacity necessary to close and hold closed all BOP 
components. The system must perform with a minimum pressure of 200 psi 
above the precharge pressure without assistance from a charging system. 
If you supply the accumulator regulators by rig air and do not have a 
secondary source of pneumatic supply, you must equip the regulators 
with manual overrides or other devices to ensure capability of 
hydraulic operations if rig air is lost.
    (d) In addition to the stack and accumulator system, you must 
install the associated BOP systems and equipment required by the 
regulations in this subpart.


Sec.  250.442  What are the requirements for a subsea BOP stack?

    (a) When you drill with a subsea BOP stack, you must install the 
BOP system before drilling below surface casing. The District 
Supervisor may require you to install a subsea BOP system before 
drilling below the conductor casing if proposed casing setting depths 
or local geology indicate the need.
    (b) Your subsea BOP stack must include at least four remote-
controlled, hydraulically operated BOPs consisting of an annular BOP, 
two BOPs equipped with pipe rams, and one BOP equipped with blind-shear 
rams.
    (c) You must install an accumulator closing system to provide fast 
closure of the BOP components and to operate all critical functions in 
case of a loss of the power fluid connection to the surface. The 
accumulator system must meet or exceed the provisions of Section 13.3, 
Accumulator Volumetric Capacity, in API RP 53, Recommended Practices 
for Blowout Prevention Equipment Systems for Drilling Wells 
(incorporated by reference as specified in Sec.  250.198). The District 
Supervisor may approve a suitable alternative method.
    (d) The BOP system must include an operable dual-pod control system 
to ensure proper and independent operation of the BOP system.
    (e) Before removing the marine riser, you must displace the riser 
with seawater. You must maintain sufficient hydrostatic pressure or 
take other suitable precautions to compensate for the reduction in 
pressure and to maintain a safe and controlled well condition.


Sec.  250.443  What associated systems and related equipment must all 
BOP systems include?

    All BOP systems must include the following associated systems and 
related equipment:
    (a) An automatic backup to the primary accumulator-charging system. 
The power source must be independent from the power source for the 
primary accumulator-charging system. The independent power source must 
possess sufficient capability to close and hold closed all BOP 
components.
    (b) At least two BOP control stations. One station must be on the 
drilling floor. You must locate the other station in a readily 
accessible location away from the drilling floor.
    (c) Side outlets on the BOP stack for separate kill and choke 
lines. If your stack does not have side outlets, you must install a 
drilling spool with side outlets.

[[Page 8430]]

    (d) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves, one of which must be remote-
controlled. For a subsea BOP system, both valves in each line must be 
remote-controlled. In addition:
    (1) You must install the choke line above the bottom ram;
    (2) You may install the kill line below the bottom ram; and
    (3) For a surface BOP system, on the kill line you may install a 
check valve and a manual valve instead of the remote-controlled valve. 
To use this configuration, both manual valves must be readily 
accessible and you must install the check valve between the manual 
valves and the pump.
    (e) A fill-up line above the uppermost BOP.
    (f) Locking devices installed on the ram-type BOPs.
    (g) A wellhead assembly with a rated working pressure that exceeds 
the maximum anticipated surface pressure.


Sec.  250.444  What are the choke manifold requirements?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, 
and abrasiveness of drilling fluids and well fluids that you may 
encounter.
    (b) Choke manifold components must have a rated working pressure at 
least as great as the rated working pressure of the ram BOPs. If your 
choke manifold has buffer tanks downstream of choke assemblies, you 
must install isolation valves on any bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings 
upstream of the choke manifold must have a rated working pressure at 
least as great as the rated working pressure of the ram BOPs.


Sec.  250.445  What are the requirements for kelly valves, inside BOPs, 
and drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly valve installed below the swivel (upper kelly valve);
    (b) A kelly valve installed at the bottom of the kelly (lower kelly 
valve). You must be able to strip the lower kelly valve through the BOP 
stack;
    (c) If you drill with a mud motor and use drill pipe instead of a 
kelly, you must install one kelly valve above, and one strippable kelly 
valve below, the joint of drill pipe used in place of a kelly;
    (d) On a top-drive system equipped with a remote-controlled valve, 
you must install a strippable kelly-type valve below the remote-
controlled valve;
    (e) An inside BOP in the open position located on the rig floor. 
You must be able to install an inside BOP for each size connection in 
the drill string;
    (f) A drill-string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the drill string;
    (g) When running casing, you must have a safety valve in the open 
position available on the rig floor to fit the casing string being run 
in the hole;
    (h) All required manual and remote-controlled kelly valves, drill-
string safety valves, and comparable-type valves (i.e. kelly-type valve 
in a top-drive system) must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit 
each manual valve.


Sec.  250.446  What are the BOP maintenance and inspection 
requirements?

    (a) You must maintain your BOP system to ensure that the equipment 
functions properly. BOP maintenance must meet or exceed the provisions 
of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, 
Maintenance; and Sections 17.12 and 18.12, Quality Management, 
described in API RP 53, Recommended Practices for Blowout Prevention 
Equipment Systems for Drilling Wells (incorporated by reference as 
specified in Sec.  250.198).
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine 
riser at least once every 3 days if weather and sea conditions permit. 
You may use television cameras to inspect subsea equipment.


Sec.  250.447  When must I pressure test the BOP system?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly valves, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Supervisor may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Supervisor may allow you to omit this test if you didn't 
remove the BOP stack to run the casing string or liner and the required 
BOP test pressures for the next section of the hole are not greater 
than the test pressures for the previous BOP test. You must indicate in 
your APD which casing strings and liners meet these criteria.


Sec.  250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:
    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) for the 
applicable section of hole. Before you may test BOP equipment to the 
MASP plus 500 psi, the District Supervisor must have approved those 
test pressures in your APD.
    (c) High pressure test for annular-type BOPs. The high pressure 
test must equal 70 percent of the rated working pressure of the 
equipment or to a pressure approved in your APD.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes. However, for surface BOP systems and surface 
equipment of a subsea BOP system, a 3-minute test duration is 
acceptable if you record your test pressures on the outermost half of a 
4-hour chart, on a 1-hour chart, or on a digital recorder. If the 
equipment does not hold the required pressure during a test, you must 
correct the problem and retest the affected component(s).


Sec.  250.449  What additional BOP testing requirements must I meet?

    You must meet the following additional BOP testing requirements:
    (a) Use water to test a surface BOP system;
    (b) Stump test a subsea BOP system before installation. You must 
use water to conduct this test. You may use drilling fluids to conduct 
subsequent tests of a subsea BOP system;

[[Page 8431]]

    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram BOP during stump 
tests and at all casing points;
    (e) The interval between any blind or blind-shear ram BOP pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe ram BOPs against the largest 
and smallest sizes of pipe in use, excluding drill collars and bottom-
hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annular and ram BOPs every 7 days between 
pressure tests; and
    (i) Actuate safety valves assembled with proper casing connections 
before running casing.


Sec.  250.450  What are the recordkeeping requirements for BOP tests?

    You must record the time, date, and results of all pressure tests, 
actuations, and inspections of the BOP system, system components, and 
marine riser in the driller's report. In addition, you must:
    (a) Record BOP test pressures on pressure charts;
    (b) Require your onsite representative to sign and date BOP test 
charts and reports as correct;
    (c) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. For subsea BOP 
systems, you must also record the closing times for annular and ram 
BOPs. You may reference a BOP test plan if it is available at the 
facility;
    (d) Identify the control station and pod used during the test;
    (e) Identify any problems or irregularities observed during BOP 
system testing and record actions taken to remedy the problems or 
irregularities; and
    (f) Retain all records, including pressure charts, driller's 
report, and referenced documents pertaining to BOP tests, actuations, 
and inspections at the facility for the duration of drilling.


Sec.  250.451  What must I do in certain situations involving BOP 
equipment or systems?

    The table in this section describes actions that lessees must take 
when certain situations occur with BOP systems during drilling 
activities.

------------------------------------------------------------------------
   If you encounter the following
             situation:                      Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the  Correct the problem and retest the
 required pressure during a test.     affected equipment.
(b) Need to repair or replace a      First place the well in a safe,
 surface or subsea BOP system.        controlled condition (e.g., before
                                      drilling out a casing shoe or
                                      after setting a cement plug,
                                      bridge plug, or a packer).
(c) Need to postpone a BOP test due  Record the reason for postponing
 to well-control problems such as     the test in the driller's report
 lost circulation, formation fluid    and conduct the required BOP test
 influx, or stuck drill pipe.         on the first trip out of the hole.
(d) BOP control station or pod that  Suspend further drilling operations
 does not function properly.          until that station or pod is
                                      operable.
(e) Want to drill with a tapered     Install two or more sets of
 drill-string.                        conventional or variable-bore pipe
                                      rams in the BOP stack to provide
                                      for the following: two sets of
                                      rams must be capable of sealing
                                      around the larger-size drill
                                      string and one set of pipe rams
                                      must be capable of sealing around
                                      the smaller-size drill string.
(f) Install casing rams in a BOP     Test the ram bonnets before running
 stack.                               casing.
(g) Want to use an annular BOP with  Demonstrate that your well control
 a rated working pressure less than   procedures or the anticipated well
 the anticipated surface pressure.    conditions will not place demands
                                      above its rated working pressure
                                      and obtain approval from the
                                      District Supervisor.
(h) Use a subsea BOP system in an    Install the BOP stack in a glory
 ice-scour area.                      hole. The glory hole must be deep
                                      enough to ensure that the top of
                                      the stack is below the deepest
                                      probable ice-scour depth.
------------------------------------------------------------------------

Drilling Fluid Requirements


Sec.  250.455  What are the general requirements for a drilling fluid 
program?

    You must design and implement your drilling fluid program to 
prevent the loss of well control. This program must address drilling 
fluid safe practices, testing and monitoring equipment, drilling fluid 
quantities, and drilling fluid-handling areas.


Sec.  250.456  What safe practices must the drilling fluid program 
follow?

    Your drilling fluid program must include the following safe 
practices:
    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just 
off-bottom. You may omit this practice if documentation in the 
driller's report shows:
    (1) No indication of formation fluid influx before starting to pull 
the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in 
the driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases 
by 75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you 
must fill the hole. You must also calculate the equivalent drilling 
fluid volume needed to fill the hole. Both sets of numbers must be 
posted near the driller's station. You must use a mechanical, 
volumetric, or electronic device to measure the drilling fluid required 
to fill the hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You 
must circulate and condition the well, on or near-bottom, unless well 
or drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break

[[Page 8432]]

down, the rated working pressure of the BOP stack, and 70 percent of 
casing burst (or casing test as approved by the District Supervisor). 
As a minimum, you must post the following two pressures:
    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the 
hole; and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the 
District Supervisor);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid;
    (i) When circulating, you must test the drilling fluid at least 
once each hour, or more frequently if conditions warrant. Your tests 
must conform to industry-accepted practices and include density, 
viscosity, and gel strength; hydrogenion concentration; filtration; and 
any other tests the District Supervisor requires for monitoring and 
maintaining drilling fluid quality, prevention of downhole equipment 
problems and for kick detection. You must record the results of these 
tests in the drilling fluid report; and
    (j) In areas where permafrost and/or hydrate zones are present or 
may be present, you must control drilling fluid temperatures to drill 
safely through those zones.


Sec.  250.457  What equipment is required to monitor drilling fluids?

    Once you establish drilling fluid returns, you must install and 
maintain the following drilling fluid-system monitoring equipment 
throughout subsequent drilling operations. This equipment must have the 
following indicators on the rig floor:
    (a) Pit level indicator to determine drilling fluid-pit volume 
gains and losses. This indicator must include both a visual and an 
audible warning device;
    (b) Volume measuring device to accurately determine drilling fluid 
volumes required to fill the hole on trips;
    (c) Return indicator devices that indicate the relationship between 
drilling fluid-return flow rate and pump discharge rate. This indicator 
must include both a visual and an audible warning device; and
    (d) Gas-detecting equipment to monitor the drilling fluid returns. 
The indicator may be located in the drilling fluid-logging compartment 
or on the rig floor. If the indicators are only in the logging 
compartment, you must continually man the equipment and have a means of 
immediate communication with the rig floor. If the indicators are on 
the rig floor only, you must install an audible alarm.


Sec.  250.458  What quantities of drilling fluids are required?

    (a) You must use, maintain, and replenish quantities of drilling 
fluid and drilling fluid materials at the drill site as necessary to 
ensure well control. You must determine those quantities based on known 
or anticipated drilling conditions, rig storage capacity, weather 
conditions, and estimated time for delivery.
    (b) You must record the daily inventories of drilling fluid and 
drilling fluid materials, including weight materials and additives in 
the drilling fluid report.
    (c) If you do not have sufficient quantities of drilling fluid and 
drilling fluid material to maintain well control, you must suspend 
drilling operations.


Sec.  250.459  What are the safety requirements for drilling fluid-
handling areas?

    You must classify drilling fluid-handling areas according to API RP 
500, Recommended Practice for Classification of Locations for 
Electrical Installations at Petroleum Facilities, Classified as Class 
I, Division 1 and Division 2 (incorporated by reference as specified in 
Sec.  250.198); or API RP 505, Recommended Practice for Classification 
of Locations for Electrical Installations at Petroleum Facilities, 
Classified as Class 1, Zone 0, Zone 1, and Zone 2 (incorporated by 
reference as specified in Sec.  250.198). In areas where dangerous 
concentrations of combustible gas may accumulate, you must install and 
maintain a ventilation system and gas monitors. Drilling fluid-handling 
areas must have the following safety equipment:
    (a) A ventilation system capable of replacing the air once every 5 
minutes or 1.0 cubic feet of air-volume flow per minute, per square 
foot of area, whichever is greater. In addition:
    (1) If natural means provide adequate ventilation, then a 
mechanical ventilation system is not necessary;
    (2) If a mechanical system does not run continuously, then it must 
activate when gas detectors indicate the presence of 1 percent or more 
of combustible gas by volume; and
    (3) If discharges from a mechanical ventilation system may be 
hazardous, then you must maintain the drilling fluid-handling area at a 
negative pressure. You must protect the negative pressure area by using 
at least one of the following: a pressure-sensitive alarm, open-door 
alarms on each access to the area, automatic door-closing devices, air 
locks, or other devices approved by the District Supervisor;
    (b) Gas detectors and alarms except in open areas where adequate 
ventilation is provided by natural means. You must test and recalibrate 
gas detectors quarterly. No more than 90 days may elapse between tests;
    (c) Explosion-proof or pressurized electrical equipment to prevent 
the ignition of explosive gases. Where you use air for pressuring 
equipment, you must locate the air intake outside of and as far as 
practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

Other Drilling Requirements


Sec.  250.460  What are the requirements for conducting a well test?

    (a) If you intend to conduct a well test, you must include your 
projected plans for the test with your APD (form MMS-123) or in an 
Application for Permit to Modify (APM) (form MMS-124). Your plans must 
include at least the following information:
    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test 
equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (b) You must give the District Supervisor at least 24-hours notice 
before starting a well test.


Sec.  250.461  What are the requirements for directional and 
inclination surveys?

    For this subpart, MMS classifies a well as vertical if the 
calculated average of inclination readings does not exceed 3 degrees 
from the vertical.
    (a) Survey requirements for a vertical well. (1) You must conduct 
inclination surveys on each vertical well and record the results. 
Survey intervals may not exceed 1,000 feet during the normal course of 
drilling;

[[Page 8433]]

    (2) You must also conduct a directional survey that provides both 
inclination and azimuth, and digitally record the results in electronic 
format:
    (i) Within 500 feet of setting surface or intermediate casing;
    (ii) Within 500 feet of setting any liner; and
    (iii) When you reach total depth.
    (b) Survey requirements for directional well. You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals 
not to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 100 feet.
    (c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
    (d) Composite survey requirements.
    (1) Your composite directional survey must show the interval from 
the bottom of the conductor casing to total depth. In the absence of 
conductor casing, the survey must show the interval from the bottom of 
the drive or structural casing to total depth; and
    (2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-
north correction. Surveys must show the magnetic and grid corrections 
used and include a listing of the directionally computed inclinations 
and azimuths.
    (e) If you drill within 500 feet of an adjacent lease, the Regional 
Supervisor may require you to furnish a copy of the well's directional 
survey to the affected leaseholder. This could occur when the adjoining 
leaseholder requests a copy of the survey for the protection of 
correlative rights.


Sec.  250.462  What are the requirements for well-control drills?

    You must conduct a weekly well-control drill with each drilling 
crew. Your drill must familiarize the crew with its roles and functions 
so that all crew members can perform their duties promptly and 
efficiently.
    (a) Well-control drill plan. You must prepare a well control drill 
plan for each well. Your plan must outline the assignments for each 
crew member and establish times to complete each portion of the drill. 
You must post a copy of the well control drill plan on the rig floor or 
bulletin board.
    (b) Timing of drills. You must conduct each drill during a period 
of activity that minimizes the risk to drilling operations. The timing 
of your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.
    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) MMS ordered drill. An MMS authorized representative may require 
you to conduct a well control drill during an MMS inspection. The MMS 
representative will consult with your onsite representative before 
requiring the drill.


Sec.  250.463  Who establishes field drilling rules?

    (a) The District Supervisor may establish field drilling rules 
different from the requirements of this subpart when geological and 
engineering information shows that specific operating requirements are 
appropriate. You must comply with field drilling rules and 
nonconflicting requirements of this subpart. The District Supervisor 
may amend or cancel field drilling rules at any time.
    (b) You may request the District Supervisor to establish, amend, or 
cancel field drilling rules.

Applying for a Permit to Modify and Well Records


Sec.  250.465  When must I submit an Application for Permit to Modify 
(APM) or an End of Operations Report to MMS?

    (a) You must submit an APM (form MMS-124) or an End of Operations 
Report (form MMS-125) and other materials to the Regional Supervisor as 
shown in the following table. You must also submit a public information 
copy of each form.

----------------------------------------------------------------------------------------------------------------
              When you                      Then you must                               And
----------------------------------------------------------------------------------------------------------------
(1)Intend to revise your drilling    Submit form MMS-124 or       Receive written or oral approval from the
 plan, change major drilling          request oral approval.       District Supervisor before you begin the
 equipment, or plugback.                                           intended operation. If you get an approval,
                                                                   you must submit form MMS-124 no later than
                                                                   the end of the 3rd business day following the
                                                                   oral approval. In all cases, or you must meet
                                                                   the additional requirements in paragraph (b)
                                                                   of this section.
(2) Determine a well's final         Immediately Submit a form    Submit a plat certified by a registered land
 surface location, water depth, and   MMS-124.                     surveyor that meets the requirements of Sec.
 the rotary kelly bushing elevation.                                250.412.
(3) Move a drilling unit from a      Submit forms Submit MMS-124  Submit appropriate copies of the well recods.
 wellbore before completing a well.   and MMS-125 within 30 days
                                      after the susepsion of
                                      wellbore operations.
----------------------------------------------------------------------------------------------------------------

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following 
additional requirements:
    (1) Your form MMS-124 must contain a detailed statement of the 
proposed work that will materially change from the approved APD;
    (2) Your form MMS-124 must include the present status of the well, 
depth of all casing strings set to date, well depth, present production 
zones and productive capability, and all other information specified; 
and
    (3) Within 30 days after completing this work, you must submit form 
MMS-124 with detailed information about the work to the District 
Supervisor, unless you have already provided sufficient information in 
a Well Activity Report, form MMS-133 (Sec.  250.468(b)).


Sec.  250.466  What records must I keep?

    You must keep complete, legible, and accurate records for each 
well. You must keep drilling records onsite while drilling activities 
continue. After completion of drilling activities, you must keep all 
drilling and other well records for the time periods shown in Sec.  
250.469. You may keep these records at a location of your choice. The 
records must contain complete information on all of the following:
    (a) Well operations;
    (b) Descriptions of formations penetrated;

[[Page 8434]]

    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Supervisor in 
the interests of resource evaluation, waste prevention, conservation of 
natural resources, and the protection of correlative rights, safety, 
and environment.


Sec.  250.467  How long must I keep records?

    You must keep records for the time periods shown in the following 
table.

------------------------------------------------------------------------
   You must keep records relating to                  Until
------------------------------------------------------------------------
(a) Drilling...........................  Ninety days after you complete
                                          drilling operations.
(b) Casing and liner pressure tests,     Two years after the completion
 diverter tests, and BOP tests.           of drilling operations.
(c) Completion of a well or of any       You permanently plug and
 workover activity that materially        abandon the well or until you
 alters the completion configuration or   forward the records with a
 affects a hydrocarbon-bearing zone.      lease assignment.
------------------------------------------------------------------------

Sec.  250.468  What well records am I required to submit?

    (a) You must submit copies of logs or charts of electrical, 
radioactive, sonic, and other well-logging operations; directional and 
vertical-well surveys; velocity profiles and surveys; and analysis of 
cores to MMS. Each Region will provide specific instructions for 
submitting well logs and surveys.
    (b) For drilling operations in the GOM OCS Region, you must submit 
form MMS-133, Well Activity Report, to the District Supervisor on a 
weekly basis.
    (c) For drilling operations in the Pacific or Alaska OCS Regions, 
you must submit form MMS-133, Well Activity Report, to the District 
Supervisor on a daily basis.


Sec.  250.469  What other well records could I be required to submit?

    The Regional or District Supervisor may require you to submit 
copies of any or all of the following well records.
    (a) Well records as specified in Sec.  250.466;
    (b) Paleontological interpretations or reports identifying 
microscopic fossils by depth and/or washed samples of drill cuttings 
that you normally maintain for paleontological determinations. The 
Regional Supervisor may issue a Notice to Lessees that prescribes the 
manner, timeframe, and format for submitting this information;
    (c) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services; or
    (d) Other reports and records of operations.

Hydrogren Sulfide

* * * * *
    9. In the newly redesignated Sec.  250.490, paragraphs (g)(4)(iv), 
(j)(13)(ii), and (p)(2) are revised to read as follows:


Sec.  250.490  Hydrogen sulfide.

* * * * *
    (g) * * *
    (4) * * *
    (iv) Restrictions and corrective measures concerning beards, 
spectacles, and contact lenses in conformance with ANSI Z88.2, American 
National Standard for Respiratory Protection (incorporated by reference 
as specified in Sec.  250.198);
* * * * *
    (j) * * *
    (13) * * *
    (ii) Design, select, use, and maintain respirators in conformance 
with ANSI Z88.2 (incorporated by reference as specified in Sec.  
250.198).
* * * * *
    (p) * * *
    (2) Use BOP system components, wellhead, pressure-control 
equipment, and related equipment exposed to H2S-bearing 
fluids in conformance with NACE Standard MR0175-99 (incorporated by 
reference as specified in Sec.  250.198).
* * * * *


Sec.  250.504  [Amended]

    10. In Sec.  250.504, in the first and last sentences, the citation 
``Sec.  250.417'' is revised to read ``Sec.  250.490''.


Sec.  250.513  [Amended]

    11. In Sec.  250.513, the following changes are made:
    A. In paragraph (a), the citation ``Sec.  250.414'' is revised to 
read ``Sec.  250.410 through Sec.  250.418''.
    B. In paragraph (b)(4), the citation ``Sec.  250.417'' is revised 
to read ``Sec.  250.490''.
    12. In Sec.  250.515, paragraph (b) is revised to read as follows:


Sec.  250.515  Blowout prevention equipment.

* * * * *
    (b) The minimum BOP system for well-completion operations must meet 
the appropriate standards from the following table:

----------------------------------------------------------------------------------------------------------------
                    When                                      The minimum BOP stack must include
----------------------------------------------------------------------------------------------------------------
(1) The expected pressure is less than 5,000  Three BOPs consisting of an annular, one set of pipe rams, and one
 psi.                                          set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or     Four BOPs consisting of an annular, two sets of pipe rams, and one
 greater or you use multiple tubing strings.   set of blind or blind-shear rams.
(3) You handle multiple tubing strings        Four BOPs consisting of an annular, one set of pipe rams, one set
 simultaneously.                               of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string..........  At least one set of pipe rams that are capable of sealing around
                                               each size of drill string. If the expected pressure is greater
                                               than 5,000 psi, then you must have at least two sets of pipe rams
                                               that are capable of sealing around the larger size drill string.
                                               You may substitute one set of variable bore rams for two sets of
                                               pipe rams.
(5) It is after February 21, 2006...........  At least one set of blind-shear rams. The blind-shear rams must be
                                               capable of shearing the drill pipe or tubing in the hole.
----------------------------------------------------------------------------------------------------------------


[[Page 8435]]

* * * * *


Sec.  250.604  [Amended]

    13. In Sec.  250.604, in the first and last sentences, the citation 
``Sec.  250.417'' is revised to read ``Sec.  250.490''.


Sec.  250.613  [Amended]

    14. In Sec.  250.613(b)(3), the citation ``Sec.  250.417'' is 
revised to read ``Sec.  250.490''.

    15. In Sec.  250.615, paragraph (b) is revised to read as follows:


Sec.  250.615  Blowout prevention equipment.

* * * * *
    (b) The minimum BOP system for well-workover operations with the 
tree removed must meet the appropriate standards from the following 
table:

----------------------------------------------------------------------------------------------------------------
                    When                                      The minimum BOP stack must include
----------------------------------------------------------------------------------------------------------------
(1) The expected pressure is less than 5,000  Three BOPs consisting of an annular, one set of pipe rams, and one
 psi.                                          set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or     Four BOPs consisting of an annular, two sets of pipe rams, and one
 greater or you use multiple tubing strings.   set of blind or blind-shear rams.
(3) You handle multiple tubing strings        Four BOPs consisting of an annular, one set of pipe rams, one set
 simultaneously.                               of dual pipe rams, and one set of blind or blind-shear rams.
(4) You use a tapered drill string..........  At least one set of pipe rams that are capable of sealing around
                                               each size of drill string. If the expected pressure is greater
                                               than 5,000 psi, then you must have at least two sets of pipe rams
                                               that are capable of sealing around the larger size drill string.
                                               You may substitute one set of variable bore rams for two sets of
                                               pipe rams.
(5) It is after February 21, 2006...........  At least one set of blind-shear rams. The blind-shear rams must be
                                               capable of shearing the drill pipe or tubing in the hole.
----------------------------------------------------------------------------------------------------------------

Sec.  250.807  [Amended]

    16. In Sec.  250.807, the citation ``Sec.  250.417'' is revised to 
read ``Sec.  250.490''.


Sec.  250.1105  [Amended]

    17a. In Sec.  250.1105(f)(1)(i), the citation ``Sec.  250.417(f)'' 
is revised to read ``Sec.  250.490(f)''.


Sec.  250.1604  [Amended]

    17b. In Sec.  250.1604 in paragraph (b), in the first and third 
sentences, the citation ``Sec.  250.417'' is revised to read ``Sec.  
250.490''.


Sec.  250.1612  [Amended]

    18. In Sec.  250.1612, the citation ``Sec.  250.408'' is revised to 
read ``Sec.  250.462''.


Sec.  250.1614  [Amended]

    19. In Sec.  250.1614, in paragraph (b), the citation ``Sec.  
250.410(b), (c), (d), and (e)'' is revised to read ``Sec.  250.455 
through Sec.  250.459''; and the citation ``Sec.  250.410(b)(8)'' is 
revised to read ``Sec.  250.456(g)''.

[FR Doc. 03-3425 Filed 2-19-03; 8:45 am]
BILLING CODE 4310-MR-P